Exploration and Production II

Exploration and Production II
Petroleum Professor Collins Nwaneri

Overview- Basic Geology Concepts
Plate tectonics results from movement and change in shape of the earth’s crust. They are three basic structure that occur when rocks are deformed: 1. Wraps- occur when the board areas of the crust rise or drop without fracturing. 2. Folds - are rock strata that have crumpled and buckled into wave like structures. - Upwarps or arches are called anticlines - Downwraps or troughs are synclines

Continued 3. Faults – occurs when rocks near the surface break, or fracture, and the two halves moves in relation to each other. Trap – is an arrangement of rock layers that contains an accumulation of hydrocarbons, and yet prevents the hydrocarbons from rising to the surface. Three main types of traps are structural traps, stratagraphic traps and combination traps.

Petroleum Exploration
Today Surface and Subsurface geological studies are used to find oil and gas. In the past oil seeps was used as a guide. Surface Geographical Studies: such as - Aerial Photographs and Satellite Images Aerial photography was used in the past, but it was expensive and difficult . Remote sensing has replaced aerial photography. It uses infrared or other means to map an area. Airplanes and satellites can carry remote sensing equipment. Lansat – currently maps all the earth landmass changes. it provides visible , thermal, and infrared images of all land masses and coastal areas on the earth. It used to detect the presence clay which is often associated with mineral deposits.

Continued Radar: used by a type of remote sensing. They bounce high frequency radio waves off land features to a satellite or an airplane for analysis of areas with potential hydrocarbon trapping structures i.e. SLAR – side-looking airborne radar is used in airplanes. Oil and Gas seeps: presence of this on the surface was used in the past to find oilfields. They occur either along fractures along reservoir or spots with formation dip up around to the surface.

Collecting Data Ways to collect information for exploration: 1. Private Company Libraries- contain large collection of drilling and production data, maps, or well logs. Oil companies usually have this data library. 2. Public Agency Records – Drilling and production data that is collected by agencies that regulate oil and gas production. Usually available to the public. 3. Databases – Information that is collected into a database by public and private organizations.

Geophysical Surveys A combination of geophysical information and surface mapping can be used to reduce the chances of drilling a dry hole. Types of Surveys: 1. Magnetic and Electromagnetic Surveys: Magnetometer surveys – finds slight variations in the earth’s magnetic field. Used to identify fractures and basement rocks that have minerals which can be a good indication of trapped hydrocarbon. Which rock type often contain minerals that are magnetic?

Continued Magnetotellurics – a type of electromagnetic surveys that uses the theory that rocks of differing composition have different electrical properties. A measure and analysis of the naturally occurring flow of electricity between rocks or across salt water can be used to reveal subsurface structures that trap hydrocarbon.

Continued 2. Gravity Surveys – uses a slight variation in the earth’s gravitational field caused by variation in the weight of rocks. Used to differentiate between light rocks and dense rocks. 3. Seismic Surveys – last exploration step before drilling for hydrocarbons. Give more precise geological information below the surface compared to the later survey methods. Why does it work? Types of seismic surveys: 1. 2-D Seismic (Seismology)

Continued 2. 3D Seismic (repeated surveys)
3. 4D Seismic (3D plus fourth dimension which is time to monitor changes in formations, mostly changes in fluid levels. Seismic waves on land is reflected to geophones. Explosive methods where used to create seismic vibrations using dynamites on land in the past. A newer method is called Vibroseis. 4. Marine Seismic Methods – same method as land except a ship is used. Seismic waves is reflected to hydrophones.

Reservoir Development
Types of tools: Well logs Driller’s logs Wireline logs Sample logs – physical samples of underground rocks. 2 types are Core samples and Cutting samples. which is more useful to the geologist?

Continued 4. Drill Stem Test – used to test a formation that has just being drilled. (Data on formation pressure and fluid composition) 5. Strat test – used to obtain geological information on a drilled hole. Stratigraphic correlation is a process of comparing geological formations between known area with unknown formations in near-by area by using information collected in driller’s log, sample logs, and electrical logs from the known areas to predict probable new reservoir with likely hydrocarbon.

Continued Maps are used in the exploration process. Types of Maps are: Base Maps and contour maps- isopach, lithofacies maps.

Aspect of Leasing An oil company must obtain a legal rights for exploitation before a reservoir can be developed. To secure the rights to explore, drill and produce from country to country is different. In the US there are 4 sources exist for the rights to petroleum: 1. Private property owner 2. State government

Continued 3. Federal government 4. Some native American tribes
Instrument used to grant the lease is called a Lease. Oil and gas lease are valid only if the ownership of the lease is established, and the provisions of the lease is explicit and legally executed.

Continued Most countries other than the US have their mineral rights owned and controlled by the government.

Types of Private Ownership
Mineral estate is defined as establishing ownership of oil, gas and mineral resources. Absolute ownership is defined as oil and gas that are owned in place, underground. Also called ownership-in-place Non-absolute ownership is defined, as no one owns the hydrocarbon until it is captured. Regardless of the two types of ownership above followed, two-thirds of onshore lands in US are privately owned.

Continued Although the rights to a mineral, oil and gas can be privately owned, it does not mean that the same person owns the surface. The following are the types of ownership: 1. Fee Simple Landowner – owns the right to exploit what wealth the land might provide. - Landowners can sell the mineral estate or a percentage of it to someone else by using a mineral deed, or sell the surface and retain all or part of the mineral estate. - The difference between a mineral deed and a mineral lease is that a leases will lose (his or her) rights to oil and gas unless production is established within the time allowed by the lease.

Continued 2. Mineral estate and surface Owners – this right depends on the state where the property is located and the minerals drilled in the sale agreement. - Some states regard the mineral estate as a possessory estate, which means a fee ownership of the minerals in place. - Some states regard the mineral estate as a servitude estate, which means it is subject to a specified use or enjoyment by one party, even though the surface is owned by another. if the minerals in an agreement are oil and gas, the mineral estate is the dominant estate and the surface is the servient estate

Continued 3. Royalty Interest Holder – owns a share or percentage of the total or gross oil and gas production. Two types: - Participating royalty interest holder: ones all or part of the mineral estate plus exclusive rights of a mineral estate owner. - Nonparticipating royalty interest holder: owns no part of the mineral estate and only receives a share of the profits for production. - Royalty deed means sale of the some fraction of the royalty interest.

The Lease and the Law A lease is a contract between a mineral estate or fee owner, the lessor and petroleum company or other party called the lessee. The lessor gives exclusive rights to the lessee. The lessee explores, drill and produce and pays a delay rental (money) each year to keep the lease current. Mineral interest is usually shared between the leesor and lesee in a percentage basis. Higher percentage that goes to the lessees is called the working interest.

Continued Example of laws are: Rule of Capture and Offset drilling rule. - Rule of capture- prevents the landowner from liability for drainage of a common reservoir when there is hydrocarbon migration from a neighbor’s land. - Offset drilling rule – an outgrowth of rule of capture, prevents a neighbor from liability if a landowners hydrocarbon reserve is being drained by the neighbor’s well. Government regulatory laws are needed to control exploratory, drilling and production of reservoirs.

Preparation for Leasing privately owned lands
Once a private owned land has being decided to be leased by an operating company, a landman (lease man or oil scout) is brought in. Landman – a person who negotiates with landowners for land options, oil drilling leases and royalties. Other functions of the landman: 1. Ownership determination 2. Validating the owners capacity to contract

Provision of the lease Conveyance, term and royalty are contained in standard lease clauses. In addition, a lease contains dates, names and signatures of parties involved, the seal and signatures of a notary public. All this are sated in the provisions essential in a lease. Types of Royalty clauses Gas royalty – traditionally payable in money. Either from the wellhead or sold outside (based on market price at the well)

Continued Shut in Royalty – for gas wells allows the lessee to maintain the lease in force by paying money to the lessor in lieu of actual production when a well is shut in, or closed off and not producing. Nonparticipating royalty Pooling and unitization clause – Share proportional interest royalties from two or more leases

Continued Drilling delay rental and related clauses – provides the lessee with 3 options 1) drill a well 2) annual payment to delay drilling within the primary terms 3) terminate the lease by not drilling nor paying annual payment Related clauses are - a dry hole clause – lessee keeps the lease if first hole is dry. continuous improvement clause – designed to keep drilling outside of the primary terms. Assignment clause - transfer of lease interest by the lessor or lessee to another party. Damage clause – a clause that makes the lessee liable fro damages or losses suffered because of drilling or production. Force Majeure clause – allows the lease to continue in force if there are uncontrollable delays during the lease while the lessee is excluded from the delay Warranty and proportionate reduction clauses – warranty clause seems to guarantee clear title and proportionate reduction clause provides a possibility that owner may own less than the described land.

Transaction after Leasing
This involves: Signing the lease Acknowledging the lease Recording the executed lease Transaction after Leasing Division Orders- Drafted based on the terms of the lease, the title opinion, and any other agreements that affects ownership of the oil and gas. Support Agreements – can be offered in the form of money or an assigned interest in the exchange of drilling a well. Execution of the lease

continued Acreage acquisition agreement – a way to acquire acreage by purchasing the lease Joint operating agreement – two or more co-owners agree to share the exploration and possibly development of a lease Joint ventures lease- similar to Joint operating agreement, but participants in this venture share liability for third party claims Overriding royalty agreements- expense free share of production and paid out of the working interest rather than the royalty share by a lessee.

Leasing Public lands: State ownership - each state has a board or agency that governs the leasing of its land Federal ownership - the federal government is the landowner of a massive size and most of the land is unavailable for oil and gas production. Leasing federal onshore lands: - Does not convey titles but grants the right to explore, drill and produce - Leasing term is 5 years for competitive leases and 10 years fro non-competitive leases.

Leasing Federal Offshore Tracts
Federal government controls the area from the states inland water to 200 miles or 8,200 feet of water depth. (Check for any update) - Federal government gives a 5 year schedule for leases it expects to sell to prospective bidders. - A typical bid includes a cash bonus and a royalty agreement.

Drilling Engineering Drilling operations are carried out during all stages of project life cycle and in all type of environments. Expenditure for drilling is a large fraction of the total project’s capital expenditure ( %) A sequence of that involves drilling operations: An initial completion of an exploratory well will establish the presence of hydrocarbon; Data gathered will be evaluated and documented; the next step will be appraisal of the accumulation requiring more wells; and finally, if the project is moved forward, development wells will have to be engineered.

Continued Overview: drilling activities will be covered and the interactions between drilling department and other E&P functions. Well Planning Drilling a well is a major investment, ranging from a few million US$ for onshore well to 100 million US$ plus for a deepwater exploration well. - Well engineering helps to maximize investment value, using the right technology and business process to successfully drill a well.

Continued Wells are drilled with one or a combination of the following objectives: 1. to gather information 2. Hydrocarbon production 3. Inject gas or water to maintain reservoir pressure or sweep out oil. 4. To dispose water, drill cuttings or CO2 (Sequestration) - Well head locations, well design and trajectory are aimed at minimizing the combined costs of well construction and seabed/surface facilities, whilst maximizing cost.

Continued Accuracy of the parameters used in the well planning phase and the well design depends on information gathered for the particular field and location. Optimum well design balances risk, uncertainty and cost with overall project value. A well design captures a comprehensive document This is used in a drilling program.

Continued Rig Types and Rig Selection Types of Rigs
The Type of rig which will be selected depend on: Cost and availability Water depth and location (offshore) Mobility/transportation (Onshore) Target zone depth and expected formation pressure Prevailing weather/metocean conditions in the area of operation Drilling crew experience (safety record). Types of Rigs Swamp barges - operate in shallow water (less than 20 ft) Drilling jackets - small steel structure that are used in shallow waters. Two or mores wells can be drilled from a drilling jack-up Jack-up rigs - can operate in water depths between 15 ft to 450 ft. Usually has three or more legs that are lowered into the seabed and then the rig will lift itself. Most common rig type. Semi-submersible - Can operated in water depths up to about 9500 ft, in most severe metocean conditions (Heavy duty semi-submersible). In addition, they can be rated up to 15,000 psi, can handle high reservoir pressure.

Continued Normally partial submerged in about 50 ft of water for stability. A large diameter steel pipe (riser) is connected to the seabed and serves as conduit for the drill-string. The blowout preventer (BOP) is also located at the seabed (subsea stack). A combination of anchors and dynamic position (DP) system assist in positioning. 5. Drill-Ship - can be used in deep and very deep water work. Heavy drillship can operate in water depth up to about 9500 ft. 6. Tender-assisted drilling- has supporting functions such has: storage, mud tanks and living quarters located on a tender, usually an anchored barge by a derrick that is used for drilling.

Drilling Systems and Equipment
Rotary rig is a basic drilling system used for offshore and onshore drilling. They three basic functions carried out during rotary drilling operations are as follows: Torque is transmitted from a power source at the surface through a drill string to the drill bit. Drilling fluid is pumped through the drill-string and up through the annulus. Used to clean the hole, cool the bit and lubricate the drillstring. Subsurface pressure above and within the hydrocarbon strata are controlled by the drilling fluid weight and BOP.

Continued Drill bits - Most frequently used drill-bits are roller-cone (rock bit) and polycrystalline diamond bit (PDC bit). - Roller cone: has three rotating bits for grinding (crushing) the rock below. Has jet nozzles. Drilling can last between 5 to 24 hrs or a little depending on formation and bit type. - PDC: last longer. Has jet nozzles. Can use high RPM with it to drill and generally provides a better rate of penetration. Bit selection depends on the composition and hardness of the formation to be drilled and the planned operating parameters. Discuss drillstring components – dp, dc, hwdp, bha and how the rotary system works. Compare top drive and kelly rigs what are some of the differences between the top drive and kelly rig, and advantages? Top Dive system - has guide rails that moves up and down inside the derrick. This drilling in 90 ft segments and on newer rigs up to 120 ft (needs two derricks)

Continued Automated pipe handling – replacement of manual labor on the rigfloor by a hydraulic system which picks up pipe from the rack, moves it up the rigfloor and then inserts it into the drillstring. Discuss circulation system and mud properties. i.e. oil based mud has the following advantages over water based mud: better lubrication of the drillstring, compatible with clay or salt formations and give higher ROP. Note: a closed-mud system is required if oil based mud or any hazardous fluid is contained in cuttings during drilling operations, instead of them being disposed onto the seabed. Discuss BOP as an important well feature , what it does and how it works. Note: The following are drilling parameters that are monitored on the rig floor: 1. Hookload

Continued 2. Torque in drillstring 3. Weight on bit 4. Rotary speed 5. Pump pressure and rate 6. ROP 7. Mud weight in and out of the hole Mention other people on rig the apart from drilling crew.

Site Preparation It Involves clearing the location to drill the well. -if no drilling activities has occurred at the place. An environmental impart assessment (EIA) is the first step. This is done to: meet legal requirements, ensure acceptability of drilling activity in the area and quantify possible risks and liabilities. - (EIA) may have to include concerns like; natural site protection and noise control, air emission, effluent and waste disposal, pollution control, visual impart, traffic and emergency response

Drilling Techniques Top Hole drilling – involves drilling the base from which to commence drilling. On land, a conductor or stove pipe is piled prior to moving the rig. Offshore, a conductor is piled or a large diameter hole is actually drilled and the conductor is lowered and cemented. Spudding occurs once the drill bit has drilled below the conductor. Surface casing is later ran and cemented. (Discuss bit type/size and drilling conditions) Intermediate and reservoir section- Normally between the top hole and reservoir. (Discuss conditions of this section for drilling this section) Directional Drilling – allows to build, hold and drop hole angles (Discuss types of Directional drilling tools and application)

Continued Horizontal drilling- usually have a steady hole angle at the lateral section. Types Long radius, medium radius and short radius. Discuss applications. Multilateral wells – ability to drill two or more wells from a central borehole. Extended reach drilling – has a horizontal displacement of at least twice the vertical depth. More difficult to drill. Discuss applications Slim hole drilling – a well with 90% or more of the length with 7 in or less in diameter. More cost reductions. Discuss why Coiled Tubing drilling – Whilst standard drilling operations use joints of drill pipes. CTD uses tubular made of high grade steel. The diameters varies between 1 ¾” and 3 ½”. It is reeled onto a large diameter drum and not segmented. Discuss advantages and Disadvantages..

Casing and Cementing Casing design starts with a conductor, then a surface casing, intermediate casing above the reservoir, a production casing across the reservoir and possibly a production liner over a deeper reservoir section. Discuss why you run casing. The main criteria for casing selection are: 1. Collapse pressure 2. Burst load 3. Tension load 4. Corrosion service 5. Buckling resistance

Continued (Discuss primary cementation, secondary cementation, plug back cementation, spacer fluid) (Discuss types of drilling problems): 1. stuck pipe 2. Fishing 3. Lost circulation (Discuss types of cost): Fixed cost Daily cost Overhead Additional-Self reading Assignment Note: Read about he different types of contracts!!!!!

Safety and Environment Issues
A research based on safety was carried out that states that: Good safety performance must start with management commitment to safety, but the level of employee commitment ultimately determines the safety performance. Types of Safety Performance Measurement: - Lost Time Incidents (LTI)- recording the number of incidents or (accidents). It causes a person to stay away from work for one day or more days. - Recordable injury frequency (RIF) - number of injury’s that require medical treatment per 100 employees.

Continued Monetary cost – means money is promised for good safety performance. Techniques used to improve company’s safety are: 1. Writing work procedure and equipment standards. 2. Training staff 3. Safety audit performance 4. The use of hazard studies in the design of plant and equipment. Best way to influence safety performance is to create a safety culture within the company.

Continued Hazard and Operating Studies (HAZOP) – determines potential hazard of an operation under normal and abnormal operating conditions and considers the probability and consequences of an accident. Examples were this studies are now applied are: Freefall lifeboats Emergency shutdown valves Protected emergency escape routes Physical separation of accommodation modules Fire resistant coatings on structural members Computerized control and shutdown of process equipment

Continued In both safety and environmental issues, the personnel should try to eliminate the hazard at source. Other safety awareness descriptions are : Accident investigation- indicates the individual causes to an accident and that a series of incidents occur simultaneously to “cause” accident. A “safety triangle” shows the approximate ratios of occurrence of accidents with different severities. An LTI is a lost time incident which causes one or more days away from work A non-LTI injury does not result in time away from work. A near hit (near miss) is an incident that causes no injury, but has the potential to do so (i.e. a falling object hitting the ground, but missing personnel) An unsafe act is where no incidents occur but that potentially could have been the cause of an incident

Continued -There are many orders of magnitude of more unsafe acts than LTIs and fatalities. - Safety management systems is a method of integrating work practices, and is a form of quality management system.

Environment Environmental standards have become a critical part of any business Individual companies have their own specific environmental management system (EMS) Global standards such as ISO14001 has being established. ISO14001 is an EMS that helps an organization to identify environment risks and impart that may occur as a result of it’s activities and ensure they are routinely managed. ISO14001 is designed to support environmental protection and the prevention of pollution in balance with socio-economic needs. Environmental Impact Assessment (EIA): The objective of An (EIA) is to document potential physical, biological, social and health effects of a planned activity. This will enable decision makers to determine whether an activity is acceptable and if not, identify possible alternatives. Typically EIA are carried out for: Seismic Exploration and appraisal drilling Development drilling and facilities Production operations Decommissioning and abandonment

Continued The results of an (EIA) assessment are documented in an environmental impact statement (EIS). The (EIS) discusses the beneficial and adverse imparts considered to result from the activity. Current Environmental Concerns Greenhouse emission Gas venting and flaring CO2 sequestration Oil and water emissions Ozone-depleting substances Waste management

Reservoir Description
This topic is divided into 4 parts: 1. Discussion of the common reservoir types (from a geological standpoint) 2. Reservoir fluids 3. Methods of data gathering 4. The ways to interpret the data Reservoir Geology This controls the producibility of a formation, that is the degree of fluid flow transmissibility and pressure communication. Three parameters that define the reservoir geology of a formation are: 1. Depositional environment: - Reservoir rocks can be classified as sediments, with a few exceptions. - Two main types are a) Siliciclastic rocks (clastic or sandstone) b) Carbonate rocks

Continued a) Clastic Rocks:
- Depositional is done by 1) Weathering (Mechanical or Chemical) and 2) Transportation of Material - Transport energy determines the size, shape and degree of sorting of sediment grains - sorting controls porosity - poorly sorted sediments equals low porosity – high water connate saturation – low hydrocarbon in pore spaces. - Well sorted sediments is the reverse. - Connate water is the water that remains in the pore spaces after the entry of hydrocarbons. - Quartz is the constituent of sandstone. Very clean sandstone contains clay mineral in the reservoir pore system. - The quantity and distribution of clay mineral in a reservoir affects both the porosity and permeability. - Reservoir estimation is complicated by the presence of clay (especially in Hydrocarbon estimation)

Continued Carbonate rocks:
- not normally transported over long distances - found mostly at initial location of origin (in-situ) - a product of marine organism Depositional environment: - sedimentation of material occurs after weathering and transportation - depositional environment is an area with typical set of physical, chemical and biological process which results in a typical type of rock - There is a relationship between depositional environment, reservoir characteristics and the production characteristic of a field. (See Table 6.1)

Continued The most valuable tool for detailed environmental analysis are cores and wire-line logs Gamma response captures changes in energy during deposition. (see fig 6.3 for the response of gamma with different depositional environments and take note of the funnel-shaped log and the Bell-shaped log response). Gamma readings are high in shale and low in sandstone. 2. Reservoir structure: Read section (6.1.2) on reservoir structure. (Will be discussed)

Continued Reservoir Fluids
Take note of the following in this section (Will highlight in next class) Types of reservoir fluids. (also see table). Physical properties of hydrocarbon fluids) i. General hydrocarbon phase behavior ii. Phase behavior of reservoir fluid types iii. Dry gas iv. Wet gas v. Gas condensate vi. Volatile oil and black oil 3. Properties of hydrocarbon gases i. Gas density and Viscosity ii. Surface properties of hydrocarbon gases iii. Hydrate formation 4. Properties of Oil i. Oil Compressibility ii Oil viscosity iii. Oil density vi. Oil formation volume factor and solution gas: oil ratio

Continued Data Gathering
It provides information that is required to estimate volume of reservoir, its fluid content, productivity and potential for development. Data gathering is not only carried at the appraisal and development phase, but throughout the life circle Reservoir data enable the quantification of fluid and rock properties. The amount and accuracy of the data available will determine the range of uncertainty associated with the estimates. - The are two types of data gathering methods: 1) Direct method - visual inspection or at least direct measurement of properties 2) Indirect method – reservoir properties are derived from a number of properties taken in the borehole The main techniques are: Direct method - Coring , Sidewall sampling (SWS), Mud-logging, Formation pressure sampling and Fluid sampling Indirect method - Wireline logging, logging while drilling and seismic - It is best to gather data before production

Continued Core and Coring Analysis:
Used to understand the reservoir rock, inter-reservoir seals and reservoir pore system In predevelopment stage, they are used to test the compatibility of injection fluids with the formation, predict borehole stability and to establish the probability of formation failure and sand production. Done in between drilling operations Made up of a core bit and core barrel Core diameters are about 3 to 7 Inches and 90 ft long Core analysis will determine: SCAL will determine: 1) porosity ) electrical test (cementation 2) horizontal air permeability and saturation exponents) 3) fluid saturation ) relative permeability 4) grain density ) capillary pressure 4) strength test

Continued Mudlogging: Wireline logging:
- It involves the direct gathering method of continuous recording and analysis to establish the nature of the formation and fluid using the returns to surface (drill cuttings and gas levels) and ROP. Sidewall Sampling: - used with wire-line after the hole has been drilled and logged Used to obtain direct indications of hydrocarbons to differentiate between oil and gas Severe crushing of the samples can obscure true porosity and permeability measurements. Wireline logging: Used to look at reservoir quality rock, hydrocarbons and source rock in exploration wells, supports volumetric estimate and geological/geophysical modelling during field appraisal and development and for hydrocarbon monitoring during production lifetime

Continued - Measures formation properties like gamma radiation, formation resistivity or formation density e.t.c Reservoir properties such as reservoir thickness, litho logy, porosity and hydrocarbon saturation are obtained from the logging tool. (See table on page 148) on wireline tool types, measurements and applications. Take note of highlighted areas. Some of the disadvantages of wireline operations: 1) Mud invasion (contamination of formation) 2) Quality of data and borehole stability issue due to increase in open hole time.(Formation damage) 3) Can be expensive

Continued Logging/measurement while drilling (LWD/MWD):
- can be obtained as real-time and recorded data - Benefits of realtime transmission are: 1. correlation of picking coring and casing points 2. overpressure detection in exploration well’ 3. logging to minimize ‘out of target’ sections 4. formation evaluation for stop drilling decisions. Discuss other areas in MWD/LWD Pressure measurements and fluid sampling: - FPT (Formation pressure tester) used to take reservoir fluid samples and pressure under reservoir conditions - Used for vertical and horizontal permeability measurements and pore pressure measurements

Data Interpretation Take note of the following in this section as discussed: Basic physical parameters for describing the reservoir. Well Correlation Maps and sections (definition of structural maps and reservoir quality maps) Net to gross ratio Porosity Hydrocarbon saturation Permeability

Volumetric Estimation
This involves the quantifying of how much oil and gas exist in accumulation - This estimate is a current estimate that changes over time - There are two methods of estimating volumetric: 1) Deterministic method- This averages the data gathered at various points in the reservoir, which can be from well logs, cores and seismic to estimate a field wide properties 2) Probabilistic method- uses predictive tools,statictic,analogue field data and input regarding the geological model to predict trends in reservoir properties away from the sample points

Continued - The section will be on deterministic methods and the techniques used for expressing uncertainty in these estimate - Field Volumetric and the anticipated recovery factors (RF’s) control the reserves in the field. (The hydrocarbons that will be produced in the future) DETERMINISTIC METHODS Volumetric estimates are required at all stages of the field life cycle Most of the time, the initial estimate of the size of an accumulation can be requested Also, a quick look estimate can be done using average field wide values, if data is limited

Continued

Continued H = total interval thickness (gross thickness), regardless of lithology. Net sand – Height of the column that can potentially store hydrocarbons. Net Oil sand – length of the net sand column that is oil bearing. Deterministic method are used in a Software and is accurate under a particular geological reservoir model. Deterministic Methods to obtain volumetric estimate on paper: 1) The area-depth method- -A hand held plan device called the planimeter is used to measure areas within selected depth interval from a top reservoir map - The areas are plotted for each depth (structure is cut in pieces of increasing depth) . Area is integrated with depth. - Connecting the measured points results in a curve describing the area-depth relationship of the top reservoir. - We can get the gross thickness (H) from a log and use it to establish a second curve that represents the area –depth plot for the base of the reservoir.

Continued - Area between the two lines is equal to the volume of rock between the two markers Area above OWC is the oil bearing GRV (AH) Other parameters needed to calculate STOIIP can be taken as averages - This method assumes that reservoir thickness is constant across the whole field and should not be used if the assumption is not reasonable approximation. (If this is the case, the area-thickness method should be used) - Can be easily carried out for a set of reservoirs or separate reservoir blocks - Practical for stacked reservoirs with common contact - Divide the area into sub-blocks of equal areas, then measure and calculate separately, if the reservoir parameters varies across the field - 2) Area-thickness method: - Used in environments where for example fluviate channels create mark differences in reservoir thickness

Continued Assumption for constant reservoir thickness does not apply
NOS map is usually prepared by the geologist and used to evaluate the hydrocarbon in place. The following example are: - Oil interval is found in a structure (Step 1) - An OWC gotten from a well log is extrapolated across the structure assuming continuous sand development (Step 1) - However, well cores and 3D seismic has identified a channel which is mapped and results in a net sand map (Step 2) The two maps are combined to get a NOS Map (Step 3) Looking at the combined map, at the fault and OWC, the sand thickness decreases to zero. Maximum thickness is indicated by the maximum NOS thickness (Zero ) meter NOS is shown by the NOS map as O meter Finally, the planimeter thickness of the different NOS contours is plotted as thickness vs. area and integrated as one. This results as a Volume of NOS ( Step 4) and not GRV

Continued If the area-depth has being applied in the above example, there will be a gross overestimation of STOIIP. NOS mapping is complex and the above example used a simple reservoir model

Field Appraisal The objective in performing an appraisal on discovered accumulations is to reduce the uncertainty in the description of the hydrocarbon discovery and provide more information for the next step. It determines both prove of hydrocarbon and also if it is non-commercial This section will cover the role of appraisal in the field life cycle, main sources of uncertainty in reservoir description and techniques used to reduce this uncertainty.

Continued Role of Appraisal in the Field life Cycle:
Appraisal is between hydrocarbon discovery and it’s development Role of appraisal is to provide cost-effective decision for the next action Value to the cost must be established For example: Cost of appraisal is $A Profit (NPV) for development with Appraisal is $(D2-A) Profit (NPV) for development without Appraisal is $D1 - The appraisal activity is worth it if $D2 – A > D1 or $A < $D2 -$D1 The following chart illustrates: Net present value (NPV) with and without appraisal

Continued

Continued Identifying and Quantifying Sources of Uncertainty
- Field appraisal is done to reduce the range of uncertainty in hydrocarbon volume in place, source of hydrocarbon and prediction of the reservoir performance during production - Parameter’s included in the estimation are: STOIIP, GIIP and UR and the controlling factors are:

Continued

Continued - RF for a reservoir is dependent on the development plan
Initial conditions alone cannot be use to get RF All of the above input parameters from the table above with the range of values of each input should be used to find STOIIP, GIIP and UR Also, in other to determine an appraisal plan, it is necessary to determine which of the parameters contribute most to uncertainty in STOIIP, GIIP or UR as seen above An example is in estimating GRV for 2 wells, after the cross-section an the base GRV is calculated using seismic data and the structure the uncertainty due to position and dip of the bounding fault and the extent of the field in the plane perpendicular to this section

Continued Steps to identify uncertainties and then to begin to quantify them are: The consideration of the factors which influence the parameters being accessed Rank the factors in order of the degree of influence Consider the uncertainties in the data used to describe the factor Same procedure may be used to rank the parameters themselves (GRV, N/G, porosity, Sh, Bo, RF), in other to indicate which has the greatest influence on the HCIIP or UR Ranking process is important in appraisal activities

Continued Appraisal Tools:
- Drillers log, sample log, wire-line and well logs (same as exploration drilling wells) - Seismic surveys (2D, 3D and 4D) - production testing - Coring Drilling deeper Interference test Horizontal drilling Adjacent well drilling (Control dip) First step in using an appraisal tool is determine what uncertainties, the appraisal is trying to reduce and what information is required to find it. For example: Fluid d contact uncertainty will best be solved by drilling well (well log) than using seismic survey.

Continued Expressing reduction in uncertainty:
The most informative method of expressing uncertainty in HCIIP or UR is by using an expectation curve. A mathematical expression of uncertainty in a parameter (i.e. STOIIP) is defined as: % Uncertainty = H – L / 2M * 100% H = High values M = Medium values L = Low values The following graph illustrates the choice of a well location position to reduce the range of uncertainty….it shows the post appraisal expectation curve to be steeper and the range of uncertainty reduced in both cases….(Discuss) The following figure shows the impact of the appraisal well A on expectation curve:

Continued

Continued The choice of location well A from existing wells should be to reduce the uncertainty The objective of this appraisal well is not to find more oil, but to reduce the range of uncertainty to estimate STOIIP Cost Benefit Calculations for Appraisal: Determination of the appraisal value information is based on the use of a decision tree. Two types of nodes: Decision nodes (rectangular) and chance nodes (circular) Decision nodes leads to actions and chance nodes lead to all possible results or situations - ILLUSTRATE with diagram……

Continued Practical Aspect of Appraisal:
In addition to cost benefit aspects. The other practical considerations which affect appraisal planning are: Time pressure to start development The views of the partners in the block Funds availability Increase appraisal incentive for tax relief purposes Rig availability Appraisal wells are normally abandoned Well is secured before moving to a development well Wells can also be used for production or injection during the field development Results of appraisal is used to determine the development plan

Reservoir Dynamic Behavior
The reservoir and well behavior under dynamic conditions help determines: 1. Fraction of produced HCIIP over the field lifetime. 2. Production rates for both hydrocarbon and water. 3. Type of unwanted fluids that will be produced (i.e. water). - The behavior dictates the revenue stream which the development will generate through hydrocarbon sales. - Reservoir and well behavior prediction are important factors in field development planning and the reservoir management during production.

Continued The Driving Force For Production
This section will cover: the reservoir fluids behavior in the reservoir away from the well in other to describe what controls the displacement of fluids towards the well. The Driving Force For Production Reservoir fluids (oil, water, gas) and rock matrix are contained under high temperatures and pressures. They are compressed relative to their densities at standard temperature and pressure. Reduction in pressure on fluids or rocks will result in an increase in Volume ( This is referred as Compressibility).

Continued Applying this is applied in a reservoir, when volume of fluid (DV) is removed from the system through production, the drop in pressure that follows will be determined by the compressibility (C) and volume(V) of the components of the reservoir system (fluids plus rock matrix).

Continued - If the compressibility of the rock matrix is negligible (true for all but under-compacted, loosely consolidated reservoir rocks and low porosity systems) then: dV= (CoVo + CgVo + CwVw)dP dV = Underground fluid withdrawal (one or two or all of oil, gas and water) Exact fluid compressibility depends on temperature and pressure of the reservoir. Gas has higher compressibility than oil or water. This results in gas expansion by a large amount for a given pressure drop. That is as production occurs from a reservoir, any free gas expands readily to replace any void space, with a small drop in reservoir pressure.

Continued If only water or oil is present in the reservoir, a greater reservoir pressure will be needed for the same amount of gas production. Reservoir fluid expansion is a function of their volume and compressibility. The reservoir fluid expansion acts as a source of drive energy which can support primary production from the reservoir. Primary production is the use of the natural energy stored in a reservoir as a drive mechanism for production.’ Secondary production is the use of external energy to the reservoir (injection of gas or water) to support the reservoir pressure as production starts to occur.

Continued - Oil formation volume factor (Bo) in rb/stb with typical ranges (1.1 – 2.0) rb/stb, Gas formation volume factor (Bg) in rb/scf) with typical ranges (0.002 – ) rb/scf and water formation volume factor (Bw) in rb/stb with typical ranges (1.0 to 1.1) rb/stb represents the relationship between the underground volumes (in reservoir barrels) and the volume at the surface condition. An additional energy drive is called pore compaction. Pore compaction results from pore fluid pressure reduction due to production from grain to grain stress increases. Leads to crushing together of rock grains and a reduction in the reamiing pore volume, which result to additional drive energy. Small drive energy (less than 3% of energy contributed by primary production but can lead to reservoir compaction and surface subsidence in case with pore fluid pressure decrease and loose rock grains.

Reservoir Drive Mechanisms
Three sets of fluid initial conditions for an oil, and reservoir and production behavior can be characterized in each case:

Continued Solution gas drive: Also called depletion drive
Has a reservoir that contains no initial gas cap or underlying active aquifer to support the reservoir pressure. Oil is produced therefore by the driving force due to expansion of oil and connate water, plus any compaction. Because the combination of the drive energy from compaction and connate water is small. The oil compressibility initially dominates the drive energy. Due to the low oil compressibility, reservoir pressure drops rapidly as production takes place, until the pressure reaches the bubble point.

Continued - The material balance equation that relates oil volume production to pressure drop in the reservoir (delta P) is NpBo = NBoi * Ce * delta (P) Bo= oil formation factor at reduced reservoir pressure (rb/stb) Boi= oil formation factor at original reservoir pressure (rb/stb) Ce= averaged compressibility of oil, connate water and rock (1/psi) N = STOIIP (stb) At bubble point, solution gas is starts to be librated from oil The rate of pressure decline per unit of production slows down.

Continued The librated gas can form secondary cap that contributes to the drive energy after migration to the reservoir crest under buoyancy forces or the influence of hydrodynamic forces (due to low pressure created from producing wells). The following chart shows the production profile for solution gas drive reservoir.

Continued Production Profile for solution gas drive reservoir

Continued First production rate is the build-up period.
At plateau period, the well is choked back. Plateau period helps to establish an optimum balance between an early oil production and avoiding unfavorable displacement in the reservoir caused by fast production that will result to loosing UR. 2% to 5% of STOIIP are typical production rates during the plateau period. Decline rate period starts until abandonment rate is reached once the plateau period is over. - Producing GOR decreases ad starts to increase (liberated gas or from secondary cap) and also can start to decrease as Gas volume in reservoir is reduced.

Continued - Water cut remains small in solution drive reservoirs (if little pressure support from the aquifer) Water cut (also called BS&W) base sediment and water is given as: Water cut = Water production (Stb) x 100% Oil plus water production (stb)

Continued Typical RF for a solution gas drive is in the range of 5 – 30%. This RF depends on the absolute reservoir pressure, solution GOR of the crude, abandonment conditions and the reservoir dip. Upper end of the RF range can be achieved by: 1) high dip reservoir (allows separation of secondary gas cap and oil, 2) high GOR, 3) light crude and 4) high initial pressure Low RF can be boosted by secondary recovery methods (water or gas injection). This methods maintain reservoir pressure, and prolong both plateau and decline period.

Continued Gas Cap drive:
initial condition for this drive is an initial gas cap. High gas compressibility provides drive energy for production and the larger gas cap results in more available energy. Locate the well perforation away from the gas cap and not close to the OWC. Slower reservoir pressure decline Increasing GOR Typical RF range for gas cap drive is about 20 – 60%. This RF is dependent on field dip and gas cap size. Small gas cap about 10% of oil volume and large gas cap about 50% of oil volume (at reservoir conditions). Abandonment conditions results from 1) very high producing GOR’s or 2) lack of reservoir pressure to maintain production.

Continued - The abandonment condition can be postponed by 1) a reduction in production from high GOR wells or 2) by recompleting these wells to produce further away from the gas cap. The drive can be supplemented by re-injecting the produced gas. The following chart shows the production profile for a gas cap reservoir.

Continued Production profile for gas cap reservoir

Continued Water Drive:
Occurs when the underlying aquifer is both large (typically greater than 10 times the oil volume) and the water is able to flow into the oil column. The ability of the water flow depends on a communication path and sufficient permeability. Water moves into the oil column to replace the void spaces created by production. Typically 5% of STOIIP is produced to measure the response in terms of reservoir pressure and fluid contact movement by the aquifer. Material balance equation is used determine the pressure support from the aquifer. Water injection can be used to assist the water drive. The reservoir pressure is maintained close to the initial pressure. (natural or addition of water injection) As a result a long plateau period and a slow decline in oil production occurs. Producing GOR may remain the same as the solution GOR at a maintained reservoir pressure above the bubble point.

Continued Large increase in water cut, over the well life results to abandonment. Water cut may be up to 90% at end of well life. RF is in the range of 30 to 70%. This RF depends on the strength of the natural drive or the efficiency of water injection for oil sweep. Combination drive: Possible to have a combined drive from the above. Gas cap drive and natural aquifer drive is the most common Material balance technique are applied to historic data to estimate contribution from each drive.

Gas Reservoirs Produced by gas expansion in the reservoir.
Gas expansion is the dominant drive compared to either connate water or underlying aquifer. Maintaining a long sustainable plateau (about 10 years) for a good sales price for gas is a major challenge. RF depends on how low the abandonment pressure can be reduced. (That is why there is surface compression stations). RF’s is typically in the range of 50 – 80%. Main difference between oil and gas field development: The economics of gas transportation The market for gas Product specifications The efficiency of turning gas into energy.

Continued When a customer agrees to purchase gas, the product quality is specified by: The caloric quality of the gas (measured in wobbe Index (WI) (MJ/m^3 or Btu/scf) The hydrocarbon dew point The water dew point and H2S. - The WI specification ensures calorific value The fraction of other gases such as: N2,CO2 and a hence a burning characteristics predictability. - Water and Hydrocarbon dew point is specified to ensure that over the range of temperature and pressure at which the gas is handled by the customer, no liquid will drop out (this could cause possible slugging, corrosion and/or hydrate) - H2S is undesirable because it is toxic and corrosive, CO2 causes corrosion in the presence of water, and N2 reduces the caloric value of gas because it is inert.

Continued Gas sales profiles; influence of contracts:
If a gas purchaser distributes gas to domestic and international end users, he typically wants the producer to provide: A guaranteed minimum quantity of gas for as long as possible. The peaks in production when required. The better the producer can meet these requirements the higher the price paid by the purchaser. Gas field production profile plateau is longer than an oil production profile plateau.

Continued When a contract is agreed with a customer, some delivery quantities will usually be specified such as: Daily Contract quantity - Supplied daily production (averaged over a period i.e. quarter) Swing Factor – amount by which supply must exceed the DCQ as requested by the customer (i.e. 1.4 x DCQ) Take or Pay agreement- the buyer pays the supplier anyway when the buyer refuses to accept a specified quantity. Penalty Clause- a penalty paid by the supplier, if he fails to deliver the quantity specified within the DCQ ands swing factor.

Continued Subsurface development of gas reservoirs
One of the major differences in fluid flow behavior for gas fields compared to oil fields is the mobility difference between gas and oil or water. Mobility indicates how fast fluid flows through the reservoir. Mobility = Permeability Viscosity In a given reservoir, gas is more mobile than oil or water. Gas wells are typically placed at the crest of the reservoir and perforated far away from the rising gas-water contact. Reasons why gas field development requires additional wells: 1) Need to provide additional deliverability as per swing requirements 2) Non-homogeneous reservoirs require more wells (closer well spacing) to drain both not very permeable reservoir and permeable reservoirs.

Continued -Non-continuous reservoirs require additional wells to drain isolated fault blocks. - More wells may be needed to produce from flat reservoir structure due to limitations in perforating higher to avoid water coning. Pressure response to production The primary drive mechanism for gas production is the expansion of the gas contained in the reservoir. RF’s for gas reservoir or gas field development depend on the continuity and quality of the reservoir: and the amount of compression installed (How low an abandonment pressure can be achieved).

Continued Alternative uses for gas reservoirs
Used for gas injection in a close oil well (support reservoir pressure decline) Miscible gas drive Gas Storage

Fluid Displacement in the Reservoir
As mentioned the RF’s for oil reservoir is the range of 5 to 70%. The reason why the other 95 to 30% remains in the reservoir is not only due to abandonment: due to Lack of reservoir pressure or High water cut , but also to the displacement of oil (fluid) in the reservoir. On a macroscopic scale, the process that leaves oil behind in the less permeable areas after oil is displaced by water in the more permeable parts of the reservoir is called By-passing. - On a microscopic scale, residual oil is the oil that remains in pore spaces even in parts of the reservoir that has being swept by water. It is in the range of 10 – 40 % of the pore space and is higher in tighter sandstone with small capillaries. - In hydrocarbon reservoirs, there is always connate water present, and commonly two-thirds are competing for the same pore space (e.g. water and oil in water drive). The permeability of one of the fluids is referred to as relative permeability. Relative permeability is a function of fluid saturation. They are measured in the laboratory on reservoir rocks samples using reservoir fluids. The following curve shows an example of a relative permeability curve for oil and water.

Continued

Continued For a given water saturation (Sw), the permeability to water (Kw) can be determined from the absolute permeability (K) and the relative permeability (Krw)……. Absolute permeability is a rock property which is a function of the pore size distribution. kw = KKrw Mobility of a fluid is the ratio of its permeability to viscosity….

Continued If oil is being displaced by water in the reservoir, the mobility ratio determines the fluid that moves preferentially through the pore space. The mobility ratio for water displacing oil is defined as…

Continued - if mobility ratio is greater than 1.0, then there will be a tendency for water to move preferentially through the reservoir and give rise to unfavorable displacement front which is called viscous fingering. - A less than 1 mobility ratio, then there will be a stable displacement. This is preferable. Note- Mobility ratio can be influenced by altering fluid viscosity (used in EOR) - Unstable displacement is less preferable due to an early production of a mixture of oil and water that may leave some oil unrecovered at abandonment conditions due to high water cut.

Continued Another force that determines fluid behavior apart from viscous force is gravity force. Gravity force separates fluids according to their density. The viscous and gravity forces play a major role in determining the shape of a displacement front in the reservoir. Estimating the Recovery Factor Ultimate Recovery = HCIIP x recovery factor (stb) or (scf) Reserves = UR – cumulative production (stb) or (scf)

Reservoir Stimulation
A computer-based mathematical representation of a constructed reservoir which is used to predict its dynamic behavior. The reservoir rock properties (porosity, saturation, permeability) and the fluid properties (viscosity and PVT properties) are specified for each grid block that is griddled up in the reservoir. At the field development planning stage. Reservoir simulation may be used to look to answer questions such as; 1) Most suitable drive mechanism (gas injection, water injection) 2) number and location of producers and injectors 3) rate dependency of displacement and RF 4) estimating RF and predicting production forecast. 5) reservoir management policy (Offtake rates, perforations)

Continued - Once production starts, data such as reservoir pressure, cumulative production, GOR, Water cut and fluid contact movement are collected. - maybe used for historical matching of the simulation model and used to adjust the reservoir model to fit observed data. - The updated model may be used for more accurate prediction of future performance.

Estimating the Recovery Factor
Ultimate Recovery = HCIIP x recovery factor (stb) or (scf) Reserves = UR – cumulative production (stb) or (scf) The main techniques for estimating RF are: Field analogues - based on reservoir rock type (tight sandstone, fractured carbonate), fluid type and environment of deposition) Analytical models – uses material balance, aquifer modelling and displacement calculations in combination of field and laboratory data to estimate RF. Reservoir simulation – a computer based mathematical representation of the reservoir construction that is used to predict its dynamic behavior. The most reliable way of generating production profiles, and investigating the sensitivity to well location, perforation interval, surface facilities constraints is through reservoir stimulation.

Enhanced Oil Recovery Seeks to produce oil which could not be recovered using a primary or secondary recovery method. The three types of EOR are: Thermal techniques : - used to reduce the viscosity of heavy crudes to improve mobility and allow oil displacement. - most common EOR method - most widely used method of heat generation is by injecting hot water or steam into the reservoir. (Done in dedicated injectors (hot water or steam drive) or injecting and producing from the same well (steam soak) .Another method is by in-situ combustion (ignition of a mixture of hydrocarbon gases and oxygen)

Continued 2) Chemical techniques: - changes the physical properties of either the displacing fluid, or the oil. Two type are polymer flooding and surfactant flooding. a) Polymer flooding- aims at reducing the amount of by-passed oil by increasing the viscosity of the displacing fluid, say water, and thereby improving the mobility ratio (M). See the above mobility ration equation. The technique is suitable where the natural mobility ratio is greater than 1. Polymer chemicals such as polysaccharides are added to the injection water. b) Surfactant flooding – targeted at reducing the amount of f residual oil left in the pore space, by reducing the interfacial tension between oil and water and allowing the oil droplets to break down into small droplets to be displaced through the pore throats. Very low residual oil

Continued saturations (around 5%) can be achieved. Surfactants
such as soaps and detergents are added to the injection water. 3) Miscible processes: aimed at recovering oil left behind as residual oil. It uses a displacing fluid which actually mixes with the oil. Best suited for high dip reservoirs. Note: It is important to establish where the remaining oil lies when deciding if to use secondary recovery or EOR methods. The following diagram shows an example of where the remaining oil may be and the appropriate method of trying to recover it.

Continued

Well Dynamic Behaviour
Wells provide the conduit for production from the reservoir to the surface, and are the link between the reservoir and surface facilities. However fluid flow from the reservoir comes under the influence of pressure drop near the wellbore, the displacement may be altered by the local pressure distribution giving rise to coning or cusping. These effects may encourage the production of unwanted fluids (i.e. water or gas instead of oil) and must be understood so their negative impact can be minimized. Estimating the number of development wells: The type and number of wells required for development will influence the surface facilities design and have a significant impact on the cost of development. The estimation of the number of wells considers: 1) The type of development (e.g. gas cap drive. Water injection, natural depletion) 2) The production/injection potential of individual wells - The number of producing wells needed to attain a production profile can be estimated from the plateau production rate and the stabilized production rates (well initial) achieved during production tests on the exploration and appraisal wells. Number of production wells = Plateau production rate (stb/d) Assumed well initial (stb/d)

Continued - A range of well initial rates should be used to generate a range of the number of wells required. (for comparison purpose in other to remove any uncertainties) Individual well performance depends on the fluid near the wellbore, the type of well (vertical, deviated or horizontal), the completion type and any artificial lift techniques used. The number of injectors required may be estimated in a similar manner, but it is unlikely that the exploration and appraisal activities would have included injectivity tests, for example water into the water column of the reservoir. The presence of fault is an element that may change the number of injection/production wells required.

Continued Fluid Flow Near The Wellbore:
The pressure drop around the wellbore of a vertical well producing is a relationship between fluid pressure against radial distance from the well. Pressure drawdown ∆PDD is the difference between the flowing wellbore pressure (Pwf) and the average reservoir pressure (P) Pressure drawdown= P - Pwf The relationship between flowrate (Q) towards the well and the pressure drawdown is approximately linear for an undersaturated fluid ( fluid above bubble point) and is defined as the productivity index (PI). - Productivity Index (PI) = Flowrate (Q) Pressure Drawdown (∆PDD) (bbl/d/psi) or (m3/d/bar) For example in an oil reservoir a PI of 1 bbl/d/psi is low for a vertical well and a PI of 50 bbl/d/psi would be high - The flowrate of oil into the wellbore is also influenced by the reservoir properties of permeability (K) and thickness (h), by oil properties viscosity ( and formation volume factor (Bo) and Skin Factor (S),

Continued which is a dimensionless number that represents changes in flow resistance near the wellbore. For a steady state flow behaviour ( effect of the producing well is seen at boundaries of the reservoir) the redial flow of oil into a vertical wellbore is represented by: The Skin term represents a pressure drop which can arise due to formation damage around the wellbore. The Damage can be caused by Invasion of solids into the formation from the drilling mud. This can be prevented by a better choice of mud and completion technique. The damage can be removed by backflushng the well at high rates or acidizing (pumping acid to dissolve the solids). In addition, the damage can be by-passed by perforations or a small fracture treatment (Skin Frac).

Continued Another common cause of Skin is partial perforation of the casing or liner across the reservoir. This component of skin is called geometric skin. It can be reduced by adding more perforations (There is a tradeoff between increased productivity and risk of more perforations close to unwelcomed fluids and gas or water coning into the well). In gas the inflow equation that determines the production rate of gas (Q) is given as: The pressure drop due to skin is dependent on the gas flow-rate (flow from laminar to turbulent). Also called “rate dependent skin”.

Continued The different form of the inflow equation for gas is due to the expansion of the gas as the pressure reduces. The expansion will increase the gas velocity and therefore cause increased pressure drop. The productivity index (PI) for gas is: When the radii flow of fluid towards the wellbore comes under the localized influence of the well, the shape of the interface between the two fluids may be altered . This can give rise to water conning and water cusping. Conning: Occurs in the vertical plane and when producing perforations are close (lies above) to the oil-water contact. This results to increased water-cut.

Continued Horizontal Wells:
Cusping: occurs in the horizontal plane, the producing perforations is not close (does not lied) to the oil-water contact. The tendency for conning and cusping increases if, The flowrate in the well increases The distance between the stabilized OWC and the perforation increases The vertical permeability increases The density difference between the oil and water reduces. - To reduce the tendency the well should produced at a low rate and the perforations should be far as possible from the oil water contact (OWC). NOTE: The same phenomena can be observed for gas (Gas coning or cusping). Horizontal Wells: The advantages of horizontal wells over vertical wells are: Increase exposure to the reservoir giving higher productivity indices (PIs) Ability to connect laterally discontinuous features, for example fractures, fault blocks. Changing the geometry of drainage, for example being parallel to fluid contacts.

Continued 1) Increase exposure to the reservoir giving higher productivity indices (PI’s) : Due to PI is a function of the length of a reservoir drained by a well, horizontal wells can give higher productivities in laterally extensive reservoirs. To estimate the initial potential benefit of horizontal wells, a rough rule of thumb can be used called productivity improvement factor (PIF). The (PIF) compares the initial productivity of a horizontal well to that of a vertical well in the same reservoir, during early radial flow.

Continued - The geometry and reservoir quality are important influences on whether horizontal wells will realize a benefit compared to a vertical well. See the illustration below: Fig: Productivity improvement factor (PIF) for horizontal wells

Continued Ref: Hydrocarbon, Exploration and Production, 2nd Edition
Plot of production rate Vs Horizontal well length. The plot above shows a diminishing return of production rate on the length of well drilled in high permeability reservoirs.

Continued The exact relationship above will depend on both fluid and reservoir properties. Poor completion may exacerbate the problem as the lower drawdown on the toe of the well compared to the heel may prevent proper clean-up of mud, filter cake and completion fluids. 2) Ability to connect laterally discontinuous features, for example fractures, fault blocks: - Horizontal wells have a large potential to connect laterally discontinuous features in heterogeneous or discontinuous reservoirs. - if the reservoir quality is locally poor, subsequent section of the reservoir may be a better quality that will provide a healthy productivity for the well. They connect a series of fault blocks or natural fractures in a manner which will require many vertical wells. 3) Changing the geometry of drainage, for example being parallel to fluid contacts: This helps reduce the effects of coning and cusping. (For example a horizontal producing well may be placed along the crest of a tilted black to remain as far away from the advancing oil-water contact as possible during water drive.

Continued Additional advantage is that if the (PI) for the horizontal well is larger, gather the same oil production can be achieved at much lower drawdown. This will also help minimize the effect of conning or cusping. The result is that oil production is achieved with less water production, which reduces processing cost and assist in maintaining reservoir pressure. Gas cresting is a distortion in fluid interface (Gas-Oil Contact near a horizontal well. Production Testing and Bottom Hole Pressure Testing: Routine production tests are performed, ideally once per month on each producing well, by diverting the production through the test separator on surface to measure the liquid flowrate, water cut and gas production rate. The tubing head pressure (also called FTHP) is recorded at the time of the production test. A plot of production rate against FTHP is made. The (FTHP) is also recorded at least once per day. It is used to estimate the well's production rate on a daily basis by reference to the FTHP Vs. production rate plot for a well.

Continued -It is important to know how much each well produces or injects in order to identify productivity or injectivity changes in the wells, and the cause can then be investigated. Production testing through the surface separator gathers information at the surface. Another important information collected during bottom hole pressure testing is downhole pressure data. This is used to determine reservoir properties such as permeability and skin. In a production well, downhole pressure measurement is typically taken by running a pressure gauge on wireline to the reservoir interval. The downhole pressure gauge can record the static bottom hole pressure (SBHP) , when the well is shut-in and flowing bottom hole pressure (FBHP), when the well is flowing. This are also referred to as a static bottom hole pressure survey and flowing bottom hole pressure respectively. A Static bottom hole pressure survey helps determine the reservoir pressure near the well, undisturbed by the effects of production.

Continued A flowing bottom hole pressure survey helps determine the pressure drawdown in a well (the difference between the average reservoir pressure and the FBHP (Pwf) from which the (PI) is calculated. Also, by the measurement of FBHP with time for a constant production rate (plot of FBHP Vs. log(time) . It is possible to determine permeability and skin parameters, and possibly the presence of a nearby fault (using a radial equation) Also measurements of SBHP with time when the well is shut in (Horner plot), these parameters can be calculated. It is common practice to record the bottom hole pressure firstly during a flowing period (pressure drawdown test), and then during shut-in period (pressure build-up test). This is because during the flowing period, the FBHP, is drawn from the initial pressure, and then the well is subsequently shut-in, the bottom hole pressure builds up.

Continued - Drawdown and build-up surveys are typically performed once a production well has been completed. This is to establish the reservoir property of permeability (k), well’s skin factor (S) and the well productivity index (PI). Unless there is an indication of some unexpected change’s in the well’s productivity during a routine production testing, only SBHP survey may be run, say once a year. A full pressure drawdown and build-up test should be run to establish the cause of unexpected changes in well’s productivity. Other production logging tool (production logging techniques), apart from temperature and pressure gauges, to acquire data include: spinners to measure flowrates, density meters to measure water, gas and oil contents.

Continued

Continued Permanent surface read-out down-hole gauges are used in critical wells (subsea wells) Permanent down-hole gauges are run with he completion. They typically measure both pressure and temperature, although venturi effect flowmeters and densimeters can also be deployed. In exploration wells, a method of well testing that eliminates the cost of running casing across the prospective interval and installing a production tubing, packer and wellhead, if unlikely the well will be used as a production well is called drill stem test (DST). The two type are Open hole DST and Closed hole DST. It is possible to run down-hole gauges to perform, a drawdown and build-up survey.

Continued Tubing Performance:
The previous slides was about the flow of fluid into the wellbore. This is referred to as “ inflow performance”. The PI indicates that as the flowing wellbore pressure (Pwf) reduces, the drawdown increases and the rate of fluid flow to the well increases. When the fluid reaches the wellbore, the fluid must now flow up the tubing to the wellhead, through the choke, flowline, separator facilities and then to the export or storage point. Each step involves overcoming some pressure drop. Pressure drop can be spilt into three parts; the reservoir pressure or inflow, the tubing and surface facilities. The linking pressures being the flowing wellhead pressure (Pwf) and the tubing head pressure (Pth). To overcome the choke and facilities pressure drop a certain tubing head pressure is required. To overcome the vertical pressure drop in the tubing due to the hydrostatic pressure of the fluid in the tubing and frictional drops, a certain flowing wellbore pressure is required.

Continued Fig: Pressure drops in the production process

Continued The Inflow performance relationship predicts the wellbore flowing pressure for a given reservoir and reservoir completion The TPR predicts the wellbore flowing pressure required to lift these fluids to surface through the tubing/. At the (wellbore) node, the pressure and the rate must be the same and therefore the point of intersection of the IPR and the TPR is the predicted well rate and the wellbore flowing pressure. This technique is called NODAL analysis. The same technique can be applied for the intersection of the TPR with the surface facilities pressure drop, where the node is now the surface pressure. Ignoring surface facilities pressure drop, the following diagram illustrates an example of the equilibrium between IPR and TPR for two tubing sizes.

Continued Fig: Reservoir performance and tubing performance

Continued From the plot above:
The reservoir with IPR1, indicates the well will not flow if the larger tubing size ( 5 ½”) is installed. (no equilibrium is achieved) But, a reservoir with IPR2 will allow greater production from the larger tubing size (5 ½”) compared to the (3 ½”) tubing size. This means for more production, a (5 ½”) tubing size should be used. The relationship between tubing and reservoir performance can aid in the selection of the right tubing size. Changes in other reservoir properties with time (i.e. water cut, reservoir pressure0 should be considered when designing fro life.

Continued The pressure drop across the choke and the facilities varies over the producing lifetime of a well. The choke is used to isolate the surface facilities from the variations in tubing head pressure, and the choke size is selected to maintain a constant downstream pressure. Initially a small orifice is used to control production when the reservoir pressure is high. As the reservoir pressure drops during the producing lifetime of the field, the choke size will be adjusted to reduce the pressure drop across the choke to help sustain production. The operating pressure of the separators can also be reduced over the lifetime of the field for the same reason.

Continued Well Completion:
The conduit for production or injection between the reservoir and the surface is the completion. - Split into two: 1) “lower completion” or “reservoir completion” for the section across the reservoir and the “upper completion” or “tubing completion” for the section above the reservoir through the wellhead The following common types of completion are : Open hole (barefoot) Pre-drilled or slotted liner Cemented & perforated liner or casing Openhole sand control screens/gravel pack Cased hole gravel pack or farc pack. NOTE: Read about the advantages and disadvantages of this completion types

Continued Completion Types

Continued The upper completion can be done using for example this four common methods. (The examples are for cased and perforated completion) Tubingless completion Tubing completion without packer Tubing completion with annulus packer Dual tubing completion with packer. Tubing configuration types NOTE: Read about the advantages and disadvantages of this tubing types:

Continued Completion Technology and Intelligent Wells
- Take note of completion equipments and what they do; as discussed in class. such equipment includes: Christmas tree, down-hole safety valve (DHSV) and others. Smart wells or intelligent wells uses remote down-hole flow control. - Take note of the equipments used and advantages as discussed in class.

Continued Artificial Lift::
- The objective of artificial lift system is to add energy to the produced fluids to either accelerate or enable production. - Pressure that is artificially maintained or enhanced by injecting gas or water into the reservoir (Pressure maintenance) is different from artificial lift system which adds energy to the produced fluids which is not transferred to the reservoir. The following are the types of artificial lift: 1) Beam pump 2) Progressive cavity pump 3) Electric submersible pump (ESP) 4) Hydraulic submersible pump (HSP) 5) Jet pump 6) Continuous flow gas lift 7) Intermittent gas lift 8) Plungers -The first five on the list are pumps (they squeeze, push or pull fluids to the surface). They transfer mechanical energy to the fluids. (In different ways) - The gas lift system add energy by adding light gas and thus lowers the overall density of the produced fluids.

Continued NOTE: Take note of the advantages and disadvantages of the different types where applicable. Subsea VS. Platform Trees: -Christmas tree is on the seabed (wet bed). This is used in subsea technology. -Platforms have trees on the surface (dry trees) NOTE: Take note of the selection criteria for offshore use.

Surface Facilities This covers the processes applied to fluids produced at the wellhead in preparation for transportation or storage. Oil and gas processing facilities have to be designed to cope with produced volumes which change quite considerably over the field lifetime, whilst the specifications for the end product remain the same. Type of processing required largely dependent upon fluid composition at the wellhead. The equipment used is significantly influenced by location. (i.e if the facilities should be based on land or offshore, tropical or arctic environments. In addition to transportation or storage specifications, considerations are given to legislation on levels of emission to the environment. A surface facilities project can be sub-divided into four parts: Wells, gathering systems, processing plant and export facilities. Some or all of the above parts can be supported on a platform (can be a land site, seabed, a fixed steel jacket or a floating structure.

Continued The design of a project starts by consideration of the process required to handle the reservoir fluids. The platform type selection which depends on the physical environment on which the process plant has to be located comes afterwards in the project design. The sections below will start with process facilities and then platform type description and selections.

Oil and Gas Processing The physical processes which oil and gas (and unwanted fluids) from the wellhead must go through to reach product specifications will be covered. Examples of such processes include: gas-liquid separation, liquid-liquid separation, drying of gas, treatment of produced water, and others. The sequence of processes required is typically determined by the process engineer. The design of the hardware to achieve the process is typically determined by the facilities engineer. Process Design: The specifications of the raw material input and the end product must be known before designing a process scheme. At the simplest level the majority of process facilities are designed to split commingled wellhead fluids into three streams of mainly gas, oil and water, as soon as possible.

Continued Description of wellhead fluids:
The main hydrocarbon properties which influence process design are: - PVT characteristics: Describes whether a production stream will be in the gas or liquid phase at a particular temperature. - Composition: Describes the proportion of hydrocarbon components (C1 – C7+) and non-hydrocarbon substances (N2, CO2 and H2S) present. - Emulsion behavior: Describes hoe difficult it will be to separate the liquid phase. - Viscosity and Density: Help determine how easily the fluids will move through the process facility. Note: If formation water production is expected, a chemical analysis of the water will also be required.

Continued Apart from fluid properties, it is important to know how much volume and rates will change at the wellhead over the life of the well or field. This is in order to size the facilities. Estimates of wellhead temperatures and pressure (over time) are used to determine how the production stream character will change. Note: if there is a planned reservoir pressure support, details of the injected water or gas which may appear in the well stream are required.

Continued Product specification:
- The end product specification of a process may be defined by a customer (e.g. gas quality), by transportation requirements (e.g. pipeline corrosion protection) or by storage considerations (e.g. pour point). - Product specifications normally do not change.

Continued Typical product specification for oil, gas and water include the following parameters: Oil - True vapor pressure (TVP), BS&W content, temperature, salinity, hydrogen sulphide. Gas- Water and hydrocarbon dew point, hydrogen composition, contaminants content, heating value Water- Oil and solids content The following table provides quantitative values for typical product specifications

Continued

Continued The process model: Process flow schemes
This describes the minimum number of steps required to achieve the end product once the specifications for the input stream and end product are known. The following factors must be considered for each process step The product yield (the volumes of gas and liquid from each stage) The inner-stage pressure and temperature The compression power required (for gas) Cooling and heating requirements Flowrates for equipment sizes Implications of changing production profile. Process flow schemes - used to present information and ideas on the process design in structural form

Continued The minimum number of steps required to achieve the transformation must be determined once the specifications for the input stream and end product are known. The following number of factors must be considered for each step of process. Product yield (the volume of gas and liquids from each stage) Inter-stage pressure and temperatures Compression power required Cooling and heating requirements Flow-rates fro equipment sizes Implications of changing production profile The following is a schematic diagram that describes the process steps requires for a mixed well stream

Continued A process flow schematic

Continued The process flow schematics:
Helps to provide information ad ideas of the process design in a structural form. For example a PFS for a crude oil stabilization might contains details of equipment, lines, valves, controls and mass and heat balance information where applicable. A process simulation is usually run under a range of operating conditions from start to end of the field life cycle. (This is to see if the process works on paper). A check will also be made to ensure that flow will start up again after a plant shutdown.

Continued Describing hydrocarbon composition:
A container full of hydrocarbon can described in a number of ways (from a simple measurement of the dimensions of the container to a detailed compositional analysis) Most appropriate method depends on what you want to do with the hydrocarbons. For example if yields of oil and gas from a reservoir sample is to be calculated, it will require a detailed breakdown of hydrocarbon composition, that is what components are present and in what quantities.

Continued Compositional data are expressed in two main ways: components are shown in volume fraction or as weight fraction. For example the volume fraction could represent the make up of a gas at a particular stage in a process and describes the gas composition as 70 % methane and 30% ethane (also known as mol fractions) at a particular temperature and pressure. Gas composition can also be expressed in mass terms by multiplying the fractions by corresponding molecular weight. The actual flow-rate of each component of gas (example in cubic meters) would be determined by multiplying the volume fraction of that component by total flowrate The following diagram illustrates an example of a gas compositional data:

Continued Fractional and actual volumes
Calculating (relative) molar mass

Continued Oil Processing
This section will describe hydrocarbon processing in preparation for evacuation from a production platform or land-based facilities. - This means spitting the hydrocarbon well stream into liquid and vapor phases and treating each phase so that they remain as liquid or vapor phase throughout the evacuation route. - for example crude must be specified to minimize gas evolution during transportation by tanker and gas must be dew point conditioned to prevent liquid dropout during evacuation of a gas plant. Separation: - oil and gas are produced into a separator a certain amount of each component will be in vapor phase and the rest in the liquid phase.

Continued The distribution of how much of each components in the hydrocarbon mixtures goes into the gas or liquid phase is dependent upon pressure, temperature and also the hydrocarbon fluid composition. For example for a single stage separator (one separator), there is an optimum pressure which yields the maximum amount of oil and minimizes the carry over of heavy components into gas phase (this is known as stripping). Additional separators may increase oil yield, but decrease incremental oil yield. Capital and operating cost will increase with each addition. Multiple stage separation can get constrained by low wellhead pressures.

Continued Separator Design:
The following are common components in a separator design. Inlet section: separates out most of the liquid phase such as large slugs or droplets in a two-phase stream. Impingement demister system: designed to intercept liquid particles before the gas outlet. Centrifugal demister(cyclone): relies on high velocities to remove liquid particles. Gas must be prevented from in the liquid phase and liquid in the gas phase. The gas in liquid phase escape to the gas phase under buoyancy forces. (must be given the opportunity “residence time”. This ease of escape is determined by the liquid viscosity. Higher viscosities require longer residence time.

Continued Residence time varies from 3 minutes for a light crude to up to 20 minutes for heavy crudes. Separator sizing is determined by three main factors: Gas velocity (to minimize mist carryover mist) Viscosity (residence time) Surge volume allowances (up to 50% over normal operating rates)

Continued Separator Types:
It can be characterized in two ways by 1) Main function (Bulk or mist separation) and 2) Orientation (vertical or horizontal). 1) knockout vessels: Most common form of basic separator No internals and demisting efficiency is poor Perform well in dirty service conditions (sand/water/corrosive products in the well stream. 2) Demister separators: Used where liquid carry-over is a problem. Both separators can be built vertically or horizontally. Vertical Separators : are often favored when high oil capacity and amp surge volume is required. Degassing can be a problem, if liquid viscosity is high (gas bubbles have to escape against the fluid) Horizontal Separators : can handle high gas volumes and foaming crudes. NOTE: In General Horizontal separators are used for high flow-rates and high gas-liquid ratios (GLRs)

Continued Dehydration and water treatment
Produced water has to be separated form oil for two main reason Customer is buying oil not water To minimize costs associated with evacuation(pumped volume, pipeline corrosion protection) Less than 0.5% water content is a typical specification for sales crude. Oil in water specifications form 10 to 100 ppm before disposal are common. As well as 40 ppm oil in water in most places. Simplest way to dehydrate or de-oil an oil-water mixture is to use settling or skimming tanks. Highly efficient equipment that combines both mechanical and chemical separation process are now commonly used.

Continued Dehydration
The equipment choice depends on how much water the stream contains. Free water knockout vessel (FWKO) is the primary separation means used for high water cut streams. Continuous dehydration tank (wash tank) may be used after a (FWKO) to reduce the water content to less than 2%. A electrostatic coalescer (plate separators)is used a further dehydrate water in from crude at offshore locations. For dehydration of very high viscosity crudes, heaters can be used in combination with dehydration tanks. When Oil and water are mixed as emulsion, dehydration becomes more difficult Emulsion can be broken using chemicals, heat or gentle agitation Chemical destabilization is the most common method used.

Continued De-oiling: Skimmer tanks used in de-oiling reduce oil concentration to less than 200 ppm (not used for offshore operations). Plate coalescer (hydrocyclones) used in de-oiling offshore, may be used in tandem with gas flotation units. De-oiling choice selection depends on throughput, variability of the feed (in terms of oil content), space and weight considerations. The oil interceptor a gravity separator type is used for small amounts of oily water in offshore and onshore locations. Plate interceptors can reduce oil-in-water content to ppm. Gas flotation and hydrocyclone processes are techniques used to reduce oil in water to less than 40 ppm in other to meet disposal standards. 40 ppm oil-water specifications typically averages over a one month period. This specification is acceptable in some areas, but 10 ppm or less is becoming more common. Produced water re-injection back into the reservoirs is an alternative method to handling water disposal.

Continued Multiphase pumps:
Can simultaneously pump oil, water and gas to effectively export processing requirements downstream to central gathering facilities. Helps to eliminate in-field equipment such as separators, compressors, individual pumping equipment, heaters, gas flares and separate flow-lines which can reduce processing costs. Can also help reduce environmental impact (less equipment and space) Subsea separation: - A typical subsea processing station includes a subsea separator (removes water from the well stream), a multiphase pump (for boosting the production rate) and a water injection pump (for discharge of separated water in a disposal well)

Continued Upstream gas processing:
This describes how gas may be processed for disposal or prior to transportation by pipeline to a downstream gas plant. -Gas and liquid are separated to remove or inhibit components in the gas which can cause pipeline corrosion or blockage in other to prepare gas for evacuation. Components which can cause difficult are water vapor (corrosion, hydrates), heavy hydrocarbons (two phase flow or wax deposition in pipelines) and contaminants such as CO2 (Corrosion) and H2S (corrosion, toxicity). Associated gas can be flared or used for gas re-injection, if there is no gas market. Gas can also be extracted to natural gas liquids (NGL), Gas lifting and use as a fuel. Pressure Distribution: - Gas is sometimes produced at very high pressures which have to be reduced for efficient processing and to reduce the weight and cost of the process facilities.

Continued Gas dehydration:
Gas that contains water vapor may have to be dried (dehydrated) Water condensation in the process facilities can lead to hydrate formation (can plug pipes and process equipment) and may cause corrosion in the presence of carbon dioxide (CO2) and hydrogen sulphide (H2S). Dehydration can be performed by a number of methods: cooling, absorption and adsorption. One of the most common methods of dehydration is absorption of water by tri-ethylene glycol (TEG) contacting.

Continued Heavy hydrocarbon removal:
Usually removed from gas to avoid liquid dropout in pipelines or to recover valuable NGL if there is no gas storage.. Cooling to ambient conditions or sub-zero temperatures Compression and absorption at low temperature. If gas compression is required following cooling . A turbo-expander. Contaminant removal: -Most common contaminates in produced gas are carbon dioxide (CO2) and hydrogen sulphide (H2S) -Both can combine with free water to cause corrosion. -H2S is extremely toxic even in very small amount Extraction of C02 and H2S is normally performed by absorption in contact towers. Amine can be used as the absorber. In the past and still in most cases CO2 from hydrocarbon was vented.

Continued Pressure elevation (gas compression)
Gas pressure may need to be increased after it passes several stages of processing. The pressure can be increased before it is evacuated, used for gas lift or re-injected. Interstage compressor may be required if gas flows from wells at a low wellhead pressure. The main types of compressors are 1) reciprocating and 2) centrifugal compressors. Gas turbine driven centrifugal compressors are very efficient under the right operating conditions but require careful selection and demand higher levels of maintenance than reciprocating compressors. Compression facilities are generally the most expensive item in an upstream gas facility.

Continued Downstream gas processing:
This describes gas processing that will be carried out at dedicated gas processing plants after upstream gas processing from gas and oil fields. This normally done before delivery to customers. The piped gas to gas plants although are generally treated to prevent liquid dropout under pipeline conditions may still contain NGLs and contaminants. Natural gas is composed of lean non-associated gas (mainly methane) to rich associated gas (have significant proportion of NGLs) NGLs are the components remaining after methane and all non-hydrocarbon components are removed (C2 – C5+) Butane (C4H10) and Propane (C5H12) can be isolated and sold as liquefied petroleum gas (LPG). Commonly seen as Bottled Gas and an energy source in remote areas. Sales gas (methane CH4 and small amounts of ethane (C2H6) usually exported in a refrigerated tanker rather than pipeline. This is known as liquefied natural gas (LNG).

Continued Terminology of natural gas

Continued Contaminant removal:
Slug catcher used to remove slugs of accumulated condensed liquid in the pipeline during gas movement in the pipeline. Gases high in H2S are subject to de-sulphurization process in which H2S is converted to elemental sulphur or metal sulphide. CO2 is removed in contacting towers. Water is removed by adsorption in molecular sieves using desiccants such as silica gel. Natural gas liquid recovery: Fractional plants are used to maximize recovery of individual NGL components. Liquefied natural gas: Contaminants such as C02, H2S, water and heavier hydrocarbons must be removed before the gas is liquefied. The LNG gas plant temperature is kept at -120 t deg. C and compressed to 60 atm/870 psi. Pressure is reduced fro storage and shipping in order to keep the gas in liquid form. LNG must be kept below -83 deg C independent of pressure.

Continued Gas to liquids:
This refers to the group of processes that convert natural GTL fuels. They are easier and cheaper to transport, market and distribute. Contains less pollutants and fine particulates than convectional liquid fuels. Have better energy yield. (for improved engine performance) Liquefied petroleum gas: Mixture of propane and butane Used as a fuel for heating appliances, vehicles and as a replacement for environmentally damaging gases previously used as refrigerants and aerosol propellants.

Facilities This covers some of the facilities required for the systems which support production from the reservoir, such as gas injection, gas lift and water injection and the transportation facilities used for both offshore and land operations. The type of production support system depends on the reservoir type. Most common are Water injection Gas injection Artificial lift Water Injection: To supplement oil recovery or to dispose of produced water. Needs to be treated before injection into the reservoir Injected at high pressure Seawater, fresh surface water, produced water or aquifer water (not from the reservoir) are possible water sources. It is important to determine what treatment is required to make the water suitable for injection. This is investigated by performing laboratory test on water samples. The principle parameters studied and their impact on injection rates or formation damage is shown on the table below:

Continued Table: Water treatment considerations

Continued Gas Injection:
Helps maintain reservoir pressure or gas disposal that cannot be flared. No need to control hydrocarbon dew point for injected gas compared to export gas Basic liquid separation is needed for injected gas Injected gas pressure is much higher than lift gas or gas pipeline pressure Compressor selection is critical Artificial Lift: Common types are gas lift, beam pumping and downhole pumping. Requires lower pressure than injection gas Similar gas treatment consideration except heavy end are not normally stripped out of the gas Gas compression can be avoided, if there is gas source of suitable pressure nearby. (adjacent gas field) - Beam pumping and ESP require a source of power.

Continued Land Based Production Facilities:
Once the process scheme has being defined, the fashion in which equipment and plant is located is determined partly by transportation considerations (e.g. pipeline specifications) and also by the surface environment. NOTE: Take note of the composition/types of well-sites, Gathering stations and Evacuation and storage as discussed in class.

Continued Offshore Production Facilities:
- An offshore production platform is like a gathering station; hydrocarbon have to be collected, processed and evacuated for further treatment or storage. NOTE: Take note of the difference between the design and layout of the offshore facilities and land facilities. Take note of the two categories of offshore platforms and the corresponding types.

Production Operations and Maintenance
During the development planning phase of a project , it is important to define how the field will be produced and operated and how the facilities are to me maintained. A typical development planning and project execution period may be 5 or 6 years, but producing lifetime of the field may be 25 years. Early input into the FDP from the production and operations group is essential to ensure that the mode of production and maintenance is considered in the design of the facilities. Over the lifetime of the field, the total undiscounted OPEX is likely to exceed the CAPEX. For this reason, it is important to control and reduce OPEX at the project design stage as well as during the production period.

Continued The operations group will develop general operating and maintenance objectives for the facilities which will address product quality, cost, safety and environmental issues. The mode of operations and maintenance for a particular project will be specified in the FDP. Both specifications that focus on the input of the production operations and maintenance departments to FDP will be discussed.

Operating and Maintenance Objectives
The guidelines when specifying the mode of operation and maintenance of the equipment items and systems, and will incorporate elements of Business objectives Responsibilities to the customers Health safety and environmental management systems Reservoir management Product quality and availability Cost control Operating and maintenance objectives for a project might include statements which covers: Technical principles (i.e. measuring hydrocarbon delivery to a specified accuracy). Business principles (i.e. meeting the company objectives of, say, maximizing the economic recovery of the hydrocarbons). Environmental Principles (i.e. complying with all local legislation)

Production Operations Input to the FDP
- The production operations department will become involved in determining how the file will be operated, with specific reference to the following table. Table: Operations and maintenance in the FDP

Continued Production:
Some of the considerations that are made in each area are: Production: Product quality specification: Starting point for determining the preferred mode of operation. Specifications such as delivery of stabilized crude with BS&W less than 0.5% and salinity of 70 g/m3 should be clearly stated in the FDP Contractual agreements: for example how the crude should be measured. The capacity and availability: sufficient capacity and availability must be provided to achieve the production targets and satisfy contracts. The mode of operation and maintenance, as well as performance of the equipment will determine the availability. Concurrent operations: - That is performing simultaneous activities of production and drilling or sometimes production, drilling and maintenance. (SIPROD). 5) Monitoring and control: - Involves the use of a combination of instrumentation and control equipment plus manual involvement to monitor and control production. For example , well monitoring can involve sending an operator to record tubing head pressure on a daily basis or use a remote computer cased system to record and control production.

Continued The benefits of a CAO includes: Increased production rates
Reduced OPEX (operating expense) i.e. less manpower cost and maintenance cost. Reduced CAPEX (capital expense) i.e. reduced instrumentation, less accommodation and office space. Increased safety: i.e. less people in hazardous areas Improved environmental protection:i.e better leak detection Improved database: i.e. more and better organized historical data. Cost of implementing CAO depends on the installed system. But in a new field development it is likely in the order of 1 – 5 % of the project CAPEX, PLUS 1-5% of annual OPEX. Testing: On production rate can be done on a drilling platform or at the centralized production facility. Ione test separators can be used on a drilling platform per drilling platform with more than one well or one test separator can be used on a production platform from more than one drilling platform - In new development, Test separators may be substituted with Multiphase metering (can measure volume of oil, gas and water without the need for separation.

Continued Metering: Production metering is done for fiscal (taxation), tariffing and re-allocation purposes. This can take place as the product leaves the production platform or arrives at a delivery point (crude oil terminal) Standardization: Equipment standardization is an area the saves cost, both in terms of CAPEX and OPEX. Flaring and venting: Driven by legislation that states maximum allowable limits for these activities. Waste Disposal: - Covers all non-useful (effluent streams) and useful product discharge of production processes which must be considered during FDP. - Example are waste discharge to sea (i.e. drill cuttings) and effluents discharged to air (i.e. hydrocarbon gases, noise e.tc) Important basic principle for waste management includes: Eliminate the waste at source (i.e. slim drilling) Re-use materials (i.e. recycling of drilling mud) Re-inject waste (i.e. drilling cuttings) Utilities systems: - Supports production operations and should be addressed when putting together a FDP.

Continued Manning: Involves the manning of production facilities which is key part of FDP. Logistics: -Refers to the organization of transport of people, supply and storage of materials. Communications: -Includes internal communication within the platforms (i.e. telephone, radio) and external systems (fax, telephone and internet) Measurement and control of operating cost: OPEX is a major issue in the FDP(Initial estimate may affect the overall profitability of a project. Useful to specify which system will measure OPEX Without measuring OPEX, there is no chance to manage it.

Maintenance Engineering Input to the FDP
This describes how the production operations will be maintained. -This is done for safety and to keep the production objective of meeting quality and quantity specifications. CAPEX-OPEX trade-offs means for example spending higher CAPEX on more reliable equipment in anticipation of less maintenance cost over the life of the equipment. - A statistical analysis of failure equipment shows a characteristic trend with time. This is described as a “bathtub curve”. See the following figure:

Continued Fig: Bathtub curve for failure frequency

Continued The following can be described from the curve:
1. Early failures: occurs almost immediately Failure rate is determined by the manufacturing faults or poor repairs. 2.Random failures: due to mechanical or human failure. 3. Wear failure: occurs mainly due to mechanical faults as the equipment becomes old. -Mean time failure (MTF): This takes note the period at which a piece of equipment is likely to fail. A maintenance strategy can then be put in place. Equipment can be maintained id different ways depending on critically (consequence of failure) and failure mode Critically is how important and equipment item is to the process. Failure mode describes the reason for an equipment failure. (Analysis of historical failures in a particular equipment.

Continued Maintenance strategies:
The two principal maintenance strategies are: Preventive and breakdown maintenance- can be combined in the same equipment or not. -Other maintenance strategies are: Breakdown maintenance: Good for equipment whose failure does not threaten production, safety or the environment and where the cost failure prevention will be greater than the consequences of failure. Preventive maintenance: Involves the inspection, serving and adjustment with the objective of preventing breakdown of equipment. Good for critical equipments Can be scheduled on a calendar basis or hour basis On condition preventive maintenance involves equipment monitoring on continuous basis to identify abnormal behavior in other to use preventive maintenance. A method of on-condition maintenance is to monitor equipment On-line. First-line maintenance involves careful inspection on equipment on a daily basis.

Continued Measurement and control of maintenance costs:
Maintenance cost accounts for a large fraction of the total OPEX of a project. Increases as facilities age (just when production and hence revenue enter into decline) The long-term cost of maintence of an item of equipment should be estimated over the whole life of the project and combined with its capital cost to select both the type of equipment and form of maintenance which gives the best full life cycle cost (on a discounted basis) while meeting the technical, safety and environmental specifications. see the following diagram.

Continued

Continued It is recommended to specify and assign cost for the actual activities which are anticipated. This is called activity based costing (allows a much more realistic estimate of OPEX rather than using a percentage of CAPEX for OPEX) Uptime means the fraction of time the plant is available. (Critical in meeting production targets)

Project and Contract Management
This will cover how and why a typical project is organized in a number of well-defined stages, and discusses the methods used to ensure that cost and time expectations are fulfilled, and ‘products’ delivered to an agreed specifications. Phasing and Organization: -A project can be defined as a task that has to be completed to a defined specification within an agreed time and for a specific price. -Oil and gas companies find it manageable to divide projects into phases, which will reflect changing skill requirements, levels of uncertainty and commitment of resources. A typical project is split into the following phase: Feasibility Definition and preliminary design Detailed design Procurement Construction Commissioning Review

Continued Fig: Project Phase

Continued Project Phasing:
The first three phases listed in the above in the project phase is sometimes defined as the pre-project stage. This is the stage in which ideas are developed and tested, but before large funding commitments are made. 1. Feasibility phase: projects are tested as concept to find out if it is technically feasible and economically viable. - The performance of the task are judged against economic criteria, availability of resources and risk. -At this stage, estimates of cost and income (production) profiles will carry a considerable uncertainty range, but are used to filter out unrealistic options. 2. Definition phase: project options are narrowed down and a preferred solution is proposed. - Work can continue to the next phase “Preliminary design” provided the project is determined viable, the resources are available and risk levels are acceptable. Preliminary design: The objective is to prepare a document that will support an application for funds. - Tighter cost estimate and the level of detail must be sufficient to give fund holders confidence that the project is technically sound and commercially robust and may also use to gain a license to proceed from government bodies.

Continued 4. Detailed design: This phase often signals a significant increase in spending as teams of design engineers are mobilized to prepare detailed engineering drawings. Used to initiate procurement activities and construction planning. At this stage the total may be 5% of the total project budget, and yet around 80% of the hardware items will have been specified. 5. Procurement: this deals with getting the right materials together at the right time and within a specified budget. A tendering process is used for items that will be obtained from a number of sources. Spending at this stage can range anywhere from 10 % to 40% of the total project cost. 6. Construction: Varies depending on the nature of the contract Normally carried out by specialized contractors working under the supervision of a company representative such as the construction manager or resident engineer. - The company representative is responsible for delivering completed works to specification and within time budget limits. He also determines the impact of problems and co-ordinate an appropriate response.

Continued 7. Commissioning: The objective is to demonstrate that the facility constructed performs to the design specifications. - The project is handed over to an operating team upon successful testing of facility or equipments. 8. Review: a project is reviewed on completion and the reason for differences between planned and actual performance are recorded. This is project phasing type is the most common approach used in the industry. Another project phasing concept that has been tested is called parallel engineering . Parallel engineering: this is a project management style aimed at significantly reducing the time span from discovery of oil and thus fast tracking new developments. - For example, appraisal, conceptual design and construction can be carried out at the same time.

Continued Project organization:
- Made up of a project manager and a project team whose composition should reflect the type of project and experience levels of both company and contractor personnel. Planning and Control: Project planning techniques are employed to prepare realistic schedules within manpower, materials and funding constraints. The following are typical types of project planning techniques: Network analysis: -Critical path analysis or ‘network analysis’ is a technique for systematically analyzing the schedule of large projects, so that activities within a project can be phased logically, and dependence identified. All activities are given a duration and the longest route through the network is known as the critical path. An example is the relationship between four activities of different duration shown in figure 1: It shows the critical path as the lower route ( 6 days), since the last activity cannot start until all the previous activities have been completed. A typical ‘activity symbol’ is shown in fig 2. It can contain other information such as Milestones (first oil, weather window and restraints).

Continued - Activity dates can be changed if completion date and intermediate key dates cannot be met. Fig 1:Project Planning network Fig 2: Activity symbol convection

Continued Bar Charts: - Whilst network analysis is a useful tool for estimating timing and resources, it is not a very good means for displaying schedules. Bar charts are used commonly to illustrate planning expectations and as a means to determine resource loading . Below is a figure that shows a bar chart with resource loading. Fig: Bar chart resources loading

Continued -The bar shows that activity ‘B’ can be performed at any time within days 2,3 and 4, without delaying the project. It also shows that the resources loading can be smoothed out if activity ‘B’ is performed in either day 3 or 4, such that the maximum loading in any period those not exceed 4 units. ‘S’-curves: plots cumulative resources weighting against time. The planned progress of the project can be illustrated and often projects need time to gain momentum and slow down towards completion. Such plots can be used to compare actual to planned progress. Can be used to determine how many extra resources that will be needed to complete a project if progress is delayed. The following figure show a ‘S’-Curve plot.

Continued Fig: Progress plot (or ‘S’ Curve)

Continued Cost Estimation and Budgets:
Cost information is required to enable decisions to be taken at each project phase. For example in a conceptual phase, this estimate may be very approximate (e.g. 40% accuracy), reflecting a degree of uncertainty regarding both reservoir development and surface options. This is sometimes referred as an ‘order of magnitude cost estimate’. As a project becomes better defined the accuracy of estimates should improve. Appropriate estimate of technical cost is important for economical analysis. Underestimating cost may lead to funding difficulties associated with cost overruns and therefore lower profitability. Setting estimate too high can kill a project The following figure illustrates a “Cost estimate evolution”

Continued Fig: Cost estimate evolution

Continued Cost estimates can usually be broken down into firm items.
Firm items such as pipelines are often estimated using charts of cost vs. size and length. The total of such item and allowances (contingency) may form a preliminary project estimate. Contingency is often made for expected but undefined changes. (i.e. cover a design and construction changes within the project scope). Minimum risk estimates are sometimes used to quantify either maximum exposure in monetary terms or, in the case of an annual work plan containing multiple projects, to help determine the proportion of firm projects. Firm projects are those which have budget cover even it cost overrun. A minimum risk estimate is one with little or no probability of overrun, and can be used to reflect the risk associated with very complex or novel projects . Can be referred as a P90 estimate ( it is at the high end of the range)’ ( see the following figure)

Continued Fig: Estimates and contingency

Continued Reasons for Contracting:
Many oil an gas companies do not consider detailed design and construction of production facilities as part of their core business. At this stage work is contracted out. Contracts are used by the oil company where: Where services by a contractor will be cheaper or more efficient than using in-house resources. Services required are of specific nature and are not available in-house. Services are required for a peak of demand for a short period of time. Types of common contracts: Lump Sum contract: contractor manages and executes specified work to an agreed delivery date for a fixed price. Penalties may be due to late completion of work and provides incentive for timely completion. Payment may be staged when agreed milestone are reached. Must favored type of contract for companies awarding work. 2. Bills of Quantities contract: the total work is split into components which are specified in detail, and rates are agreed for the materials and labor. The basis of handling variation to cost are agreed.

Continued 3. Schedule of rates contract: The labor cost is agreed on a rate basis, but the materials and the exact hour are not specified. 4. Cost Plus Profit contract: all cost incurred by the contractor are reimbursed in full, and the contractor the then the contractor then adds an agreed percentage as a profit fee. Contract choice depends on the type of work, and the level of control which the oil company wants to maintain. Participating arrangements is another current contract type where an oil company considers the contractor as a partner and works closely with the contractor at all stages of the project development. This type of contract usually contains a significant element of sharing risk and reward of the project.

Petroleum Economics Petroleum economics provides the tools with which to quantify and access the financial risks involved in the field exploration, appraisal and development, and is the consistent basis used for comparing alternative investments. Basic Principles of Development Economics: This will cover economics of a new field development. Economic analysis of investment opportunities requires the gathering of data or information such as: capital cost, operating cost, anticipated cost, anticipated hydrocarbon production profiles, contract terms, fiscal (tax) structures, forecast oil/gas prices, the timing of the project and the expectations of the stakeholders in the investment. The economic model for investment (divestment) evaluation opportunities is normally constructed as a spreadsheet. The uncertainties in the models input data are handled are handled by establishing a base case (often using the ‘best guess’ values of key input variables) and then investigating the impact of varying the values of key inputs in a sensitivity analysis.

Continued Based on a simple model of investment for a proposed project (Fig 1): Any investment proposal may be considered as an activity which absorbs money and later generate money The money invested may be raised as a loan capital (debt) or from shareholders capital (equity) The net money generated (revenue minus cost) may be used to repay interest on loans and loan capital The residual balance belongs to shareholders, and is called shareholders profit. This can be paid out as dividends or re-invested in the company. Cash flow of a project or project cashflow (project net cash flow) is the forecast of the money absorbed and the money generated during the project lifetime. The project cash flow forms a basis of the economic evaluation methods which will be described. From a cash flow a number of economic indicators can be derived and used to judge the attractiveness of the project.

Continued Fig. 1: Overall flow of funds for a project

Continued Constructing a Project Cashflow:
Construction of a project cash flow requires information from a number of different sources. An example of the principal inputs is shown in the following table 1:

Continued Table 1: Elements of a project cashflow

Continued It is important to request the current range of uncertainty when collecting data from the sources above For any one case, the project cash flow is calculated on a annual basis (per year) Project net cash flow (project cashflow) = Revenue – expenditure Revenue items: Due to the sale of hydrocarbons Oil and gas prices are assumed in determining the gross revenues Oil price forecast is often based on a flat real terms (RT) price (i.e. increasing in price at the forecast rate of inflation) or flat money of the day (i.e. price stays the same and is thus declining in RT) -Gas price forecast may be indexed to the crude market price or be taken as a negotiated price with an identified customer. Expenditure items: -Depends on the fiscal system of a government A typical case is using CAPEX for items (i.e. cost of platform, pipelines) whose useful life exceeds 1 year. Using OPEX for items (i.e. services, overhead) whose useful life is less than 1 year It is recommended to use OPEX based on specific activities anticipated during the field lifetime (e.g number of workovers, cost of forecast manpower requirements) It is common to use OPEX broken into Fixed OPEX and Variable OPEX in the absence of the recommendation, although not accurate.

Continued -Fixed OPEX: proportional to the capital cost of items to be operated (based on a percentage of the cumulative CAPEX) Variable OPEX: proportional to the throughput (related to the production rate (oil or gross liquids). Hence the relationship: OPEX should not ignore overhead cost (doses not reduce with production decline) Sum of OPEX and CAPEX is called Technical Cost or Total cost - OPEX can be referred to lifting cost and CAPEX can be referred to developmental cost

Continued Host government:
A fiscal system refers to the manner at which the host government claims an entitlement to income from the production and sale of hydrocarbons. - Royalty is the percentage of gross revenues from the sale of hydrocarbons, and may be paid in cash or in kind (e.g. Oil). The prevailing oil price is used. In addition to royalty, one or more taxes such as petroleum tax , plus the usual corporation tax on company profits - Fiscal allowance are allowances made against the gross revenue before applying the tax rate. Commonly include royalty, OPEX and capital allowances.

Continued -Royalty is charged from the start of the project, but tax is only payable once there is a positive taxable income. Capital allowance: Fiscal allowances made for investment in capital items (i.e. CAPEX) which is made through capital allowance. - Not a cash flow item but calculated to enable the taxable income to be determined - This capital allowance approach is a petroleum economics approach used to calculate tax payable - The there most common type are: 1. Straight line capital allowance: simplest of the three types, allowances for capital asses is claimed over a number of years in equal amounts per year. i.e. 20 % of the initial CAPEX per year for 5 years. (See the table below)

Continued

Continued 2. Declining balance method:
Each year the capital allowance is a fixed percentage of the unrecovered value of the asset at the end of the previous year.

Continued 3. Depletion method or unit of production method:
This method attempts to relate the capital allowance to the total life of the assets (i.e. the fields economic lifetime) by linking the annual capital allowance to the fraction of the remaining reserves produced during the year. The capital allowance is calculated from the unrecovered assets at the end of the previous year, times the ratio of the current year’s production to the reserves at the beginning of the year.

Continued As long as the ultimate recovery remains the same the capital allowance per barrel of the production is constant. But this is rare, making this method more complex in practice.

Continued Project net cash flow:

Continued

Continued Production sharing contracts:

Continued Negotiation between the government and the oil company.
- An advantage of PSCs is that the government includes a time schedule and fiscal terms for exploration, appraisal and development, and production periods.

Continued NOTE: A Few other sections discussed in class is omitted from here on (Not needed for mid-term exam). But will be included for Final Exam.

Risk Analysis - Oil and Gas business involves major investment in all stages of the field life cycle. During the gaining access, exploration and appraisal stages, expenditure does not guarantee a return and at the development stage major investments are made in anticipation of returns over a long period of time. For this reasons, it is important that careful technical and commercial risk analysis is performed when making decisions on investment in the industry This section will summarize the risk analysis techniques already introduced in the areas of exploration and appraisal and HSE, and will cover some methods used in managing risk in developments.

Risk Definition and Unit of Measure
Project risk can be conveniently be defined be defined as the impact of the outcomes on the stakeholders. For example, oil price is an input in economic analysis, and the risk of price variation will be measured in terms of project NPV. Risk can have a negative outcome and also a positive outcome (opportunity) In general monetary terms is a convenient measure of risk, allowing comparisons to be made, and justifying expenditure to reduce risks with a potential negative impact . Risk can also be defined as the product of impact and probability, still measured in dollars. Quantitative risk assessment is a technique used to reduce an event with high impact but low probability (i.e. major plant disaster) in terms of the product of the two.

Continued Summary of Risk Analysis Techniques in Exploration and Appraisal In the exploration phase, the key uncertainties are the presence of a petroleum system through which hydrocarbons could be accumulated in a reservoir, and the volume of those hydrocarbons, if present The two uncertainties are combined into a risked volume by multiplying together the POS and the volumetric range, often represented by an expectation curve. In summary the risk volume of hydrocarbon reserves can be calculated as follows (from the table below)

Continued

Continued It is common to generate a distribution curve for the range of uncertainty in volume of hydrocarbons reserve, often using the Monte Carlo simulation techniques to combine the uncertainty in each input parameter. This distribution curve is multiplied by POS to yield a range of risked reserves. As shown in the figure below. Fig: Range of risked reserves for an exploration well

Continued In this example, the p90, p50,p10 reserves are approximately 10, 50 and 100 MMstb, and the POS is 30%, so the p90, p50, p10 risked reserves are approximately 3, 15 and 30MMstb. - The diagram in the figure above is useful in indicating that the probability of exceeding any level of reserves, for example the probability of exceeding 100 MMstb is approximately 3% and the probability of exceeding 50 MMstb is approximately 15%. In this case, a commercial threshold for development can be provided by the economist, which states that the probability of commercial success (sometimes quoted as POSc) is 15% for the 50 MMstb reserve. The simplest way to represent the risked reserve range is to multiply the reserves volume by the POS to quote the estimated risked reserves. The Expected Monetary Value (EMV) of a project is calculated by multiplying the estimated unrisked Net present value (NPV) of the project for a certain number of reserve volumes by the probability of Success (POS) minus the a Present value (PV) of the exploration cost. EMV = Unrisked reserve (NPV) X POS – (PV) exploration cost - If exploration is successful, the next phase of the field life cycle would involve considering appraisal of the discovery.

Continued During the appraisal phase the key driver is to efficiently reduce uncertainty by data gathering in order to size the development of facilities appropriately. Data gathering typically involves shooting seismic, drilling wells and performing production tests. The value of information (VoI) represents the maximum value of the appraisal data and is equal to the value of the project with the information less the value of the project without the information. Value of Information (VoI) = Value of project with information – Value of project without information A decision tree is a convenient way to estimate the VoI.

Continued - A sensitivity analysis can be performed to determine the maximum cost of appraisal before it would be better to just commit to development with out knowing the true reserves size. This cost would be the maximum VoI, spending more than this on the appraisal information cannot be justified.

Risk Analysis For Major Capital Investment in Projects
Risk can represent potential negative impact or upside opportunity, and are identified in order to plan mitigation against those with potential negative impact and to take advantage of upsides identified. It is common to perform risk analysis at several stages of the development planning, so that risk items can be identified early and actions planned accordingly This is to avoid going too far on a project which will eventually prove to be unfeasible. A stage - gate process is used by many companies in this process This process breaks the project into phases, with an approval required at each stage before progressing through the ‘gate’ to the next stage. The earlier the risk or opportunity is identified, the more potential there is to create value, and similarly the later is identified the more erosion of project value will typically occur. (See the figure below) The following table briefly indicates the activities which occur at each stage.

Continued Fig: A typical stage-gate process

Continued The asses stage can be called the Appraise stage in some companies, and the stage-gate process clearly has its roots in a traditional planning and control approach NOTE: A Few other sections discussed in class is omitted from here on (Not needed for mid-term exam),But will be included for Final Exam.

Exploration and Production II

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