Presentation on theme: "Evolution of Oil Production in the Bakken Formation"— Presentation transcript:
1 Evolution of Oil Production in the Bakken Formation Julie A. LeFeverNorth Dakota Geological Survey
2 Plays of the Bakken Formation Several episodes of exploration have addressed the Bakken Formation over the years. Beginning with the initial discovery in 1953, the Bakken has been a significant contributor to the North Dakota economy. Over 44 million barrels of oil have been produced from this formation, and as we shall see there is a large potential to add to that total.Exploration history of the Bakken can be divided into 3 major episodes –1. Conventional Drilling (pre-1987)2. Horizontal Drilling of the upper Bakken Shale (post-1987)and, 3. Horizontal Drilling of the Bakken Middle Member (2001 to present)Conventional Bakken (pre-1987)Cycle 1 – Antelope Structure (1950s – 60s)Cycle 2 – Depositional Edge (1970s – 80s)Horizontal Drilling of the Bakken Shale (post-1987)Horizontal Drilling of the Bakken Middle Member(2001 to present)
3 Conventional Bakken Cycle 1 – Antelope Field Discovery WellStanolind - #1 Woodrow StarrInitial Potential (536 BO; 0.1 BW)Antelope Field52 wells; 12.5 million BO; 10 BCF Gas“Sanish Sand”Completion MethodPlays of the Bakken FormationConventional Plays (pre-1987)Convention plays can be split into two separate cycles. The first cycle concerns the exploration and development of the Antelope structure, the second, concerns exploration of the depositional limit of the formation (now referred to as the Bakken Fairway).Cycle 1 – Antelope Fielda. Discovered in 1953 (in a well with an unsuccessful Madison test)1. Stanolind Oil – #1 Woodrow Starr (SWSE Sec 21, T152N, R94W)2. IP – 536 BO, 0.1 BWb. Offsets were disappointing, further development did not occur until 1956 when Northern Pump Co. drilled and completed the #1 Ella Many Ribs for 320 BOPD; majority of the wells for the field were drilled in the 1950s and 60s. During the 1980's, renewed interest in the Antelope structure resulted in the drilling and completion of a number of wells along the southern end of the feature.c. Antelope Field - To Date1. 52 wells with an average IP of 209 BO; 13 wells are still producing2. 67,798 BO for 2003; Cumulative total in excess of 12.5 million barrels of oil and 10 BCF Gas3. “Sanish Sand” – Additional production for this field is from the “Sanish Sand,” a thin, highly burrowed porous silty sandstone that occurs between the lower Bakken shale and the underlying Three Forks Formation.4. Early wells were drilled with salt-based mud systems. Later wells used oil-based systems to prevent dissolution and resulting casing collapse of the overlying Madison salt section. Typical completion method consisted of perforating the well followed by a sand-oil fracture stimulation treatment.
4 Conventional Bakken Exploration between Cycles Elkhorn RanchShell Oil Co. - #41X-5-1 GovernmentNesson Anticline#1 B.E. HoveIP BOPD, 3 BWPDCompletion MethodExploration Between CyclesAfter the development of Antelope Field, exploration for the Bakken proceeded slowly. The tight, impermeable reservoir of the Bakken required natural fractures in order to produce. The next discovery in the formation did not occur until Shell Oil Company used seismic methods to discover Elkhorn Ranch Field along the depositional limit in what is now known as the “Bakken Fairway”.Elkhorn RanchThis was a typical Williston Basin discovery. The well was originally an Ordovician Red River test that recovered oil on a drill stem test in the Bakken. The Shell Oil Company - #41X-5-1 Government (NENE Sec. 5, T.143N., R.101W.) was subsequently completed and tested 136 BOPD and a trace of water. However, the well was located in a remote area and was often shut-in during inclement weather. It flowed an average of 50 BOPD until 1964, when its casing collapsed and the well was plugged and abandoned. Further development did not occur in this area until Gulf Oil Corporation completed the #1-5 Gulf Sunbehm USA (NWNW Sec. 5, T.143N., R.101W.).Nesson AnticlineAnother notable discovery at this time was along the Nesson Anticline. The #1 B.E. Hove (SWNW Sec. 2, T.154N., R.95W.) was drilled by Pan American Petroleum Corporation in Hofflund Field. During its initial test, the well flowed 756 BOPD and 3 BWPD.Completion Method – After perforating, the well was treated with 10,000 gallons of acid. Production problems resulted in two workovers with additional acid treatments followed by a water-based fracture stimulation. The well produced for two years with a cumulative production of 62,700 barrels of oil. It was plugged in 1969 due to non-commercial production and collapsed casing.By the end of this phase of drilling, production from the Bakken extended for the entire length of the structure.
5 Conventional Bakken Cycle 2 – Depositional Limit Stratigraphy & StructureThin BakkenMultiple PaysFolds, Faults or BothCompletion MethodsCycle 2 - Depositional LimitThe other area of Bakken activity is along the depositional limit of the Bakken Formation (“Bakken Fairway”). The activity in this area began in the late 1970's.Stratigraphy and StructureThe Bakken Formation exhibits an onlapping relationship. The stratigraphy of this area is relatively simple. The Three Forks Formation is overlain by the remaining, stratigraphically higher, members of the Bakken. The Bakken, in turn, is overlain by the carbonates of the Lodgepole Formation. As the Bakken thins, it sets the stage for the next cycle of drilling. The thin Bakken is much more susceptible to fracturing and fracturing is necessary for production.Wells along the Bakken Fairway are not limited to Bakken production. Most of the fields have multiple pays that are associated with structural features such as folds, faults, or both. These features contribute to the fracturing of the Bakken and may enhance the quality of the reservoir.Successful wells were those that encountered natural fractures. Less than successful wells (those not encountering natural fractures) were perforated in the Bakken Shale and produced for awhile. Produced oil was collected and used as part of a sand/oil fracture stimulation treatment; diesel was commonly substituted for produced oil. Approximately 78% of the wells drilled in this cycle were stimulated with some kind of fracture treatment. This treatment was necessary for economic reserves. (One study shows that there was only one well that wasn’t treated that had economic reserves.).Also, water and the Bakken do not mix. The Bakken Shale is an oil-wet reservoir and wells that had water introduced to the system had difficulty unloading the water. Introduction of water into the system could be through drilling fluids, acidizing, or fracture stimulation methods. Acidizing Bakken wells also creates problems, the treatment may react with the pyrite present in the shales forming and iron hydroxide precipitate.The long history of vertical drilling in the state set the stage for horizontal drilling. Vertical drilling established that the wells with significant vertical production were draining fractured reservoirs. Problems encountered in the completions of vertical wells could be factored into the completion methods of the horizontal wells. And vertical Bakken production showed decline curves for established wells showed a characteristic rapid drop in production over the first year, followed by steady production with virtually no decline.The drilling activity changed greatly along the depositional edge after 1987 when Meridian Oil drilled and completed the first horizontal well in the Bakken Formation.
6 Horizontal Drilling of the Upper Bakken Shale Meridian - #33-11 MOIDrilled verticalCored, Logged, Drill Stem TestedDrilled Horizontally ft8 ft - upper Bakken ShaleIP: 258 BOPD & 299 MCF gasCost: $2 millionHorizontal Drilling of the Upper Bakken ShaleMOI #33-11The first horizontal well, the #33-11 MOI, was initially drilled vertically. It was cored, logged, and drill stem tested, all of which indicated that the formation was tight. Meridian then backed up the hole and kicked off at 9,782 ft. Horizontal drilling was attained at 10,737 ft (3273 m; measured depth) with a resulting radius of 630 ft. The well was completed on September 25, 1987 for 258 BOPD and 299 MCF of gas. The well had a horizontal displacement of 2,603 ft and is now producing in the upper Bakken shale that is 8 ft thick. The decline curve for the #33-11 was remarkably stable for the first two years until additional nearby wells came online. The well has produced 357,671 BO and 6,381 BW through December 2003.
7 Learning Curve Meridian -#33-11 MOI 3 set of 10 wells End of Play 57 days to drill27 days to drill vertical borehole12 days to drill horizontal section$2 million3 set of 10 wells35 days to drill at a cost $1.08 millionEnd of Play$900,000 (same as a vertical well)Learning CurveAs previously stated, it all began with the drilling and completion of the #33-11 MOI by Meridian Oil, Inc. The well took 57 days to drill, 27 days to drill the vertical borehole and 12 days for the horizontal section, at a cost of $2 million. The third set of ten wells drilled by Meridian, which were further down the learning curve, had an average cost of $1.08 million and took 35 days to drill. By the end of the play, Meridian Oil, Inc. was touting the fact that they could drill and complete a horizontal Bakken well for essentially the same price as the drilling and completion of a vertical well, around $900,000. They were well advanced on the learning curve.
8 Horizontal Drilling of the Upper Bakken Shale Drilling MethodsGeneral ProblemsSuccessful well = high volumes of oilHorizontal Drilling of the Upper ShaleIt has been 17 years since the first horizontal Bakken well. During the play, 22 operators drilled horizontal wells. Half were one or two well programs. It is important to spend a moment on the successes and failures and what we’ve learned in an effort to apply them to a new play concerning this un-conventional reservoir.Drilling Methodsa. Medium radius well with one horizontal leg – 2500 to 3500 ft in length (optimal wellbore length is ftb. Drilled underbalanced or slightly underbalanced with inverted mud systemc. Wells are completed with slotted liners tied back to casingGeneral ProblemsDrilling problems were common. It was common to be stuck in the hole. At that point, the key seemed to be time. A certain amount of circulation time was required to break up the rock material into small enough chips to send it up the wellbore.Fractures in the shales were sensitive to drawdowns either through Drill Stem Testing or Production testing. Once fractures were closed production dropped off. Also, were there were no natural fractures, there was no production. There was no ability to stimulate the wellbore (as was done in vertical holes). Also, the wellbore still had the same sensitivity factors to fluids that were encountered in the vertical holes.Additional problems resulted from fracture communication. Interference between wellbores was documented to extend over large areas. Horizontal wellbores were found to have an effect on a vertical wellbore 2500 to 3000 ft away. The large scale regional fractures are highly interconnected, causing pressure and fluid communication to extend over several sections (Evidence for hearing in front of the North Dakota Industrial Commission, May23, 1990). This interference would not show up immediately, but would generally become apparent after a month of continuous production.Wells also required periodic workovers to remove accumulated salt and fines.However, where successful wells were capable of producing high volumes of oil (IP’s in excess of 1900 BOPD).
9 Horizontal Drilling of the Bakken Middle Member Richland County, MontanaNorth DakotaThe next portion of the talk will look at the current play concerning the Bakken – horizontal drilling of the middle member.Current drilling activity is largely centered around Richland County, Montana. We will examine at the current play – the geological aspects and the drilling methods. From there we will move the North Dakota portion of the Williston basin and look at what’s been done and what the potential is for additional Bakken horizontal activity.
10 Williston Basin Study Area Richland Co. McKenzie Co. AB SK MB MT ND SD WYRichland Co.McKenzie Co.MTNDStudy Area
11 Richland County, MT Stratigraphy SouthNorthMississippian Lodgepole FormationUpper Shale MemberTransitional Facies – L7Upper (Productive)Bakken FormationMississippianRichland County, MTStratigraphyThis schematic diagram is a north-south cross-section along the Montana-North Dakota border and represents the stratigraphy in the play area. It hopefully shows the onlapping relationship of the Bakken Formation in the Williston Basin. Each successively higher member within the Bakken has a greater distribution than the preceding member. As we move southward in Richland County, Montana, the lower units pinch out against the Devonian Three Forks. In the main play area, only the upper 2/3rds of lithofacies 2 and the overlying upper shale member of the Bakken remain. This does have some trapping effect since the Devonian Three Forks and Mississippian Lodgepole rocks are impermeable.Lithofacies 2Devonian Three ForksLowerTransitional Facies - L1Lower Shale Member
12 Balcron Oil - #44-24 Vaira SESE Sec. 24, T.24N., R.54E. GRDensity PorosityLodgepole Fm.10000upperBakken Fm.middleBalcron Oil - #44-24 Vaira (SESE Sec. 24, T.24N., R.54E.)This shows a typical log from the play area in Richland County, MT. This example is from the Balcron Oil - #44-24 Vaira (SESE Sec. 24, T.24N., R.54E.) A bit of background on this well – the Bakken was penetrated at 9995 to Interval was Cored and DST’d. Perforated from and completed for 83 BOPD and 61.4 MCFGPD (completed on 02/14/89). This well was not given a stimulation treatment. The well was re-entered and a horizontal leg was drilled in November The lateral came online in January 2004 increasing production from 33 BO/Month to 228 BO/Month, initial water cut was 15% but steadily decreased with production. Cumulative production for the wll from 1989 to present was 127,871 BO and 1178 BW.The Vaira has a well defined log characteristic for the porosity zone of interest. A distinctly cleaner gamma-ray log characteristic and log porosity of approx. 10%. This is the zone of interest.Three Forks Fm.Neutron Porosity
13 SESW Sec. 13, T.23N.,R.56E. AHEL #1 H8 Nevins Richland County, MT ft.SESW Sec. 13, T.23N.,R.56E. AHEL #1 H8 Nevins Richland County, MTBakken/Three Forks ContactThe RocksI have selected a series of core photographs to illustrate the rocks associated with the play in Richland County. The photographs were taken of a core from Richland County, Montana. The American Hunter #1 Nevins was drilled and completed in 1991 and was the discovery well for Three Buttes. It was a horizontal well in the upper shale, it was originally completed for 60 BOPD. Currently the well has produced a total of 32,324 BO, 53 BW, and 6032 MCF of gas. The scale bar in these photographs represents 1 inch.This slab photo is a typical example of the Three Forks Formation in the area. The Three Forks consists of an interbedded sequence of tan fine-grain sandstones to siltstones and light brown claystones. Structures include parallel laminations that are locally brecciated (probably due to the dewatering of the sediments) and cross-ripple laminations. The sequence is highly cemented and impermeable forming a good bottom seal.This well is in an area that lacks the lower Bakken shale, therefore the middle member sits unconformably on the underlying Three Forks. It is common to see abundant debris (as shown here) along the contact.
14 Middle Member Lithofacies 2 SESW Sec. 13, T.23N.,R.56E.AHEL #1 H8 NevinsRichland County, MTMiddle Member Lithofacies 2This is the basal portion of the Bakken middle member in Richland County. As is evident in the photograph, it consists of a brownish-grey, argillaceous siltstone with burrows and small clay drapes.
15 Middle Member Lithofacies 2 (producing facies) SESW Sec. 13, T.23N.,R.56E.AHEL #1 H8 NevinsRichland County, MTMiddle Member Lithofacies 2 (producing facies)Continuing up section - This rock is immediately below the upper Bakken Shale. It is similar to the previous photo, but is more bioturbated. This is the zone that is producing from the horizontal wells in Montana.
16 Upper Shale/Middle Mbr Contact 10582 ftSESW Sec. 13, T.23N.,R.56E.AHEL #1 H8 NevinsRichland County, MTUpper Shale/Middle Mbr ContactMoving further up hole, we see the presence of the upper Bakken shale.
17 BLCS Structure Map ft Montana North Dakota Contour Interval To place the project in a current day framework, I’ve included a structure map on the base of the last Charles Salt. No outstanding structural features are present on the surface over the study area. The map shows a gradual deepening towards the center of the basin; the only other noticeable feature is the presence of the Nesson Anticline in eastern McKenzie County.Contour IntervalMontanaNorth Dakota
18 Formation Limits Montana North Dakota Bakken Formation UpperMiddleLowerPrairie Salt EdgeTo re-emphasize the onlap nature of the members of the Bakken, I have included this map. Plotted here are the limits of each of the members. As you can see, each successively higher member extends further to the southwest.MontanaNorth Dakota
19 Isopach of the Bakken Formation 140130120110An isopach map of the Bakken Formation shows a gradual thickening towards the center of the basin. Thicknesses range from 0 to 50 feet for the majority of the study area, with a maximum of 90 feet.10090Contour Interval8070605040302010MontanaNorth Dakota
20 Isopach of the Upper Member Bakken Formation This is a map of the upper Bakken shale and is presented to give an idea of their distribution through the area. The principal importance of the shale to this area is as a source rock, it is what is supplying the oil to the play. Again, it extends further than the underlying middle member.Contour IntervalMontanaNorth Dakota
21 Isopach of the Middle Member Bakken Formation An isopach of the Middle Member of the Bakken Formation shows why the play is where it is. Unlike the isopach of the total Bakken and the isopach of the upper Bakken shale, there is a noticeable trend present. Data for the middle member shows a zone approximately 2 to 3 townships wide by 72 miles long. In this area, the middle member reaches a thickness of 35 feet before decreasing in thickness and continuing its gradual thickening towards the center of the basin. Remember we are only dealing with the basal two lithofacies in this area, so this is an anomalous thickness.Contour IntervalMontanaNorth Dakota
22 Middle Member Porosity Zone %Contour IntervalThis is a map of the zone previously shown on the log from the Vaira well. It is apparent that the anomalous thickness contoured on the previous map is related to the presence of this unit. It has the same orientation, from the northwest-southeast and, in fact would overlie, the trend on the previous map.The thickness is contoured over the log porosity (indicated in colors). The thickness of the producing interval reaches a maximum of 14 feet and has a consistent log porosity between 8 and 12%.The other porosity zone contoured (to the north) is one that occurs within the middle member. This zone has limited distribution and occurs between the two shales. I think it is important to note its presence. Facies changes within the middle member suggest that these may be common and potentially productive. Another higher lithofacies (Lithofacies 3) can be easily mapped throughout northwestern North Dakota and is productive along the Nesson Anticline.McKenzie Co.Richland Co.Contour Interval: 2 ft.
23 Bakken Middle Member Prairie Salt EdgeftThis is the same shaded map of the middle member with the zero edge of the Prairie Salt plotted. It is probably more than coincidental that the edge of the Prairie Salt aligns with the thick section within the middle Bakken member through this area. The southward protrusion of the salt edge is probably a reflection of the well control for that area. Wells in that area have salt that is 5 feet or less in thickness.The Prairie does have an effect on this area. The trend that is strongly present in Montana can be traced into North Dakota as far as Mondak. The contour map is somewhat misleading, the zone is present in North Dakota but not as continuous as the map shows. This is probably related to the presence of the salt southeast on Mondak.Contour IntervalMontanaNorth Dakota
24 Bakken Middle Member Prairie Salt ftTo further emphasize that point, this map shows the underlying middle member Bakken isopach (shaded), the isopach of the producing zone, and the limit of the Devonian Prairie Salt (blue). The lighter blue line is the 5 foot contour interval for the Prairie salt.This map further illustrates the correlation between the salt edge, the thickness of the middle Bakken member, and the porosity zone.Contour IntervalMontanaNorth Dakota
25 Richland County80 Producing Fields 1. Red River Fm 2. Madison Fm 3. Bakken Fm 4. Duperow Fm 5. Interlake Fm20 Fields produce(d) from the Bakken FormationRichland CountyLooking at the statistics for Richland County, prior to the current Bakken play there were 80 producing fields in the county - 23 with production from the Bakken.08/2004
26 Bakken Formation Richland County, MT Historically –42 Bakken wells + 8 commingled wellsCurrently –127 Bakken ProducersHorizontals – 92 producers, 1 PNA, 1 DryTotal production2000 – 2,618,982 BO2003 – 5,284,378 BO2004 – 3,275,061 BO (thru August, 2004)86 Producing Fields, 23 - Bakken ProductionBakken Formation Richland County, MTHistorically –50 wells, including commingled wells, produced from the Bakken prior to the current play.According to the Montana Board of Oil & Gas, statistics through the end of August 2004 show that:a wells currently produce from the Bakkenb. 94 horizontal wells producers, 1 PNA, and 1 Dryc. 61 well are currently listed as spuddedd. 69 wells are permittedThe impact of the current activity is easy to see based on the total production from Richland County. Production has doubled in 2003, and is still increasing.There are now 86 producing fields in Richland County. Of those 86, 23 produce from the Bakken.08/2004
27 Drilling & Completion Bakken Horizontals Two laterals to a 1280 spacing unitWell is stimulated with large fracture treatment (~920,000#, gelled water/sand frac)Cost $2.2 millionBOPD initiallyVirtually no waterDrilling and Completion of Bakken HorizontalsTechnology has finally caught up to the Bakken Formation. The ability to fracture stimulate these horizontal wells is what makes this play work. Whereas, in the late 80s-early 90s wells had to rely on encountering natural fractures to supply the oil; the wells in this play create their own fractures (as the early vertical holes did).Wells generally consist of two 4000 to 5000 ft laterals drilled on a 1280-acre spacing unit. Also, unlike the previous play, the middle member is drilled with a saturated brine instead of inverted muds. The zone generally has between 7 to 12% porosity, a permeability of .01 to .02 millidarcies, and 70 to 80% oil saturation. Once drilled, the well is then treated with a 650,000 to 1 million pound gelled water-sand frac.Due to high gas content, it is common for the wells to flow for quite a while before having to be put on pump.The per well cost is approximate $2.2 million with the potential for the well to produce 500 to 700 BOPD initially, leveling off at 250 BOPD with virtually no water.
28 Horizontal Drilling of the Bakken Middle Member Richland County, MontanaNorth DakotaHorizontal Drilling of the Bakken Middle Member – North DakotaNext, I would like to look at the North Dakota portion of this play, what’s happened and it’s potential.Production from the middle member of the Bakken is not new to North Dakota. There have been a few wells, primarily along the northern Nesson anticline that have been perforated in and produced from the Bakken middle member. The Bakken in these wells was not the primary target; that was deeper usually the Devonian Winnipegosis. The Bakken was generally a bailout zone, perforated because the wells were reaching their economic limit or had no other production. Production from these wells was limited.The first horizontal middle member well has been drilled in North Dakota. Several have been permitted with several companies stating their intentions to bring the play over from Montana. Let’s look at what they might potentially find.
29 Lithofacies of the Middle Member Upper ShaleLithofacies 5 - SiltstoneLithofacies 4 – Interbedded Dark Grey Shale and Buff Silty SandstoneLithofacies 3 - SandstoneProductiveFive lithofacies within the middle member of the Bakken Formation have been identified. This facies are pervasive throughout the basin – in Montana, North Dakota, Saskatchewan and Manitoba.Briefly –Lithofacies 1 consists of light grey, greenish- grey, or brownish-grey argillaceous siltstone. It is generally massive, cemented with calcite, and has scattered pyrite nodules and fossils (crinoids and brachiopods). Locally the unit is burrowed. Porosity is intergranular.Lithofacies 2 consists of greenish-grey to brownish-grey, argillaceous siltstone or sandy siltstone to brownish-grey, very fine grained sandstone. Small scale clay drapes are present, as well as burrows. Productive in MontanaThere are three parts to Lithofacies 3. The upper and lower third consists of wavy to flaser bedded, light to medium grey, argillaceous to sandy siltstones and brownish-grey, very fine-grained sandstones with local claystones. The middle third consists of a medium grey, dark grey, or greyish-tan, fine- to medium-grained sandstone that may be massive, cross-bedded, or thinly laminated. ProductiveLithofacies 4 consists of alternating medium grey argillaceous siltstones, light to medium grey very fine-grained sandstones and dark grey shale. The unit is thinly laminated, display planar and cross-ripple laminations, moderately bioturbated in places, and locally cemented.Lithofacies 5 is a medium to light grey, massive to wispy laminated siltstone that is generally cemented.Lithofacies 2 – Interbedded Dark Grey Shaleand Buff Silty SandstoneProductive in MTLithofacies 1 - SiltstoneLower Shale(From LeFever and others, 1991)
30 Lithofacies 3 Lithofacies 3 Lithofacies 3 is a sandstone-siltstone bed that occurs in the middle of the member throughout the northern portion of North Dakota and into Saskatchewan and Manitoba. It is highly productive in Saskatchewan with a long production history from Rocanville and Roncott Fields.In North Dakota production from vertical wells in this facies is marginal and found in 9 fields along the northern Nesson Anticline including Temple, Stoneview and North Tioga. It has an easily mappable log characteristic throughout North Dakota with a notably cleaner response on the GR curve.All of these wells with the exception of one were completed as a bailout zone. This facies is generally coarser grained and cleaner than the rest of the middle member and usually contains a greater amount of cementation. Thickness of the pay zone is 12 ft with 7-12% porosity. Completions generally consisted of acidization and a gelled water-sand fracture treatment. It is interesting to note that the best producer in Stoneview underwent the least amount of acid treatment suggesting that acidization probably releases fines that plug porosity and permeability.It is also interesting to note that where these wells produce the Bakken Shales are not mature. The fact that these wells and the fields in Canada produce indicates that the 45 degree oil is capable of migrating throughout the middle member.
31 SENW Sec. 11, T160N, R95W Conoco, Inc. - #17 Watterud “A” GRResProducing ZoneUpper L2 FaciesConoco, Inc. – Watterud “A” #17This well from Stoneview Fields shows the porosity zone that produces along the northern Nesson Anticline, although similar in characteristics to that seen in Montana, it is not the same facies. This facies has higher sand content, is massive, laminated, or cross-bedded, and is not burrowed.
32 Joilette Oil (USA), LLC. #1-17R Robert Heuer Sadler FieldRe-entry of a Madison Test (02/13/1981)Bakken Completion03/05/2004IP – 87 BOPD, 150 MCF, 142 BWPDFracture StimulatedProducing Zone – Lithofacies 3Joilette WellAs I mentioned earlier, North Dakota has had their first horizontal well drilled into the middle Bakken in Sadler Field. The well was a re-entry into a Madison test. One lateral leg was drilled with a sidetrack. The lateral was then treated with gelled water-sand frac and tested. An initial potential of 87 BOPD, 150 MCF, and 142 BWPD was reported for this well.Although results were not like what has been seen in Montana, remember that this is a different facies which would probably require adjustments to the completion method. There is always a learning curve.
33 What Do We Know? Rocks Types (Montana=North Dakota) Salt Collapse Additional Productive SectionLithofacies 3, “Sanish”, lower Lodgepole LimestoneSalt CollapseCompletion MethodsHigh Production RatesWhat Do We Know?We know that there is no state line faults. The same facies that produce in Montana are present and potentially productive in North Dakota. We may have a slight change in composition, locally rocks may be slightly more silty/sandy or have a higher clay content. These changes may require slightly different completion techniques (referring us back to our learning curve).We also know that we have additional productive section. Lithofacies are thicker by proximity to the depositional center. We have proven production from an additional Lithofacies 3. We also have an additional section at the base of the Bakken – the “Sanish sand”. This is a significant producer at Antelope Field and occurs throughout the “Bakken Fairway” (depositional edge of the Bakken). This highly burrowed sandstone/siltstone facies is probably related to salt collapse and may be productive. Also, the lower Lodgepole Limestone between the upper Bakken shale and the False Bakken may be another potential target. Detailed mapping of all of the zones will be required to determine the best location to tap into the Bakken resources.We know there are large areas where salt collapse has played an important role on Bakken deposition and fracturing. Detailed examination of these areas could turn out to be quite profitable.We now have the ability to stimulate horizontal wells. We know from past history that the Bakken doesn’t like to give up its oil easily. It requires some sort of fracture system (in the early 90s it was a natural one). Now, that fracture system can be artifically generated to open the Bakken up to production. The drilling of these wells with 2 long horizontal legs and stimulating them with a large frac treatment is expensive ($2.2 million) but can lead to a very profitable well (especially at current oil prices).We know that the Bakken is capable of high production rates. We saw that from the first horizontal drilling play in the late 80’s-early 90’s. Science has shown us that the Bakken is a premier source rock and is capable of generating extreme amounts of oil (some estimates are up to 413 Billion Barrels). We know the rocks is overlain and underlain by a thick section of very tight rock. This leaves us with an overpressured reservoir with a potential for great production.
34 Conclusions Horizontal Drilling Middle Member = Success Conclusions I think it can be demonstrated that the potential for success from horizontally drilling the middle member is great. There will be a learning curve associated with the wells – just as in every other play. Technology has advanced enough to better enable the recovery oil from this formation.There is one question I would like everyone to think about and that is – “Where is the oil for this play actually coming from?” – the middle member or the upper shale??Volumetrics on the middle member show that it certainly has necessary reserves. Past history tells us that the upper shale is capable of the high production rates that are seen in Montana. Has technology now provided us with a way of producing the upper shale in a stable environment.