Automating Continuous Gas Lift

Standard System Configuration Produced Hydrocarbons Out Injection Gas In Side Pocket Mandrel with Gas Lift Valve Completion Fluid Single Production Packer Standard System Configuration This shows a standard manual valve configuration with a Merla (choke) valve (not shown) on the gas injection line. The StarPac replaces the Merla valve and will generally be a bolt in swap. The Merla valve (or StarPac) controls the flow of gas to these gas lift valves.

Continuous G/L Application INCREASED PRODUCTION DECREASED INJECTION As you increase gas injection rate, you get more liquid rate up to a point of diminishing returns. The idea is to get near the knee of the curve, so that you get the most liquid without using too much gas. The other point to be made is that you can get more flow for the same gas if you lift from the bottom of the well. Note that beyond the blue dots, if you add more gas, you don’t get much more liquid. A well that is optimized is operating near the blue dots.

Problems with Manual System Changing Surface Conditions Changing flow rates due to fixed valve position Can’t maintain flow at optimal position Surging Intermittent Flow Surface conditions means conditions at the surface of the well (above the waterline). This includes the pressure of the gas to the manifold or Merla. The back pressure on the well (separator pressure), etc. Since the Merla is a manual valve, as the inlet pressure changes, the outlet pressure and flow rate change. If the pressure swings far enough, the gas lift valve (poppett) may close until pressure builds. With smaller swings, the flow rates vary a lot. In either case, you get surging and intermittent flow. What that means it that the well burps gas, then flows a slug of liquid, then burps gas, etc. This does not produce optimal liquid flow rates. Surface conditions change due to compressors going up or down, wells being shut in or started up, changes in injection rates on other wells, changes in choke settings on other wells, etc.

Well 1 This is actual data from a well in Angola. Each tab is for a different well. The bottom of the sheet shows the oldest data, the top shows the newest data. The data on line four is after a StarPac was installed. All data below line 4 is with a manual Merla valve. BOPD Barrels of Oil per day BWPD Barrels of Water per day BFPD Barrels of fluid per day BS&W Barrels of solids and water % MCFDP Thousand standard cubic feed per day of produced gas MCFDF Thousand standard cubic feed per day of formation gas MCFDI Million standard cubic feed per day of injection gas GLR Gas Liquid Ratio (total gas in cu ft/liquid production in barrels) IGLR Injection gas/total produced fluid (the thing we want to optimize) FGOR Formation oil gas ratio TP Tubing Pressure CP Casing Pressure FL Flow line pressure (pressure at the production manifold) Production line pressure TCK Tubing wellhead choke (choke valve position) ICK Indicated valve position (which tick mark on the hand-wheel) This is a snapshot from a 2 hour period, taken every 30 days. Don’t worry too much about all the numbers, we’ll discuss a few on the next slide.

Manual valve data Well 1 Date BOPD MCFDI ICK 15-Jun-00 566 814 13 8-May-00 312 1019 10-Apr-00 432 1004 12-Oct-99 250 938 This is a summary of data from the previous slide, big enough to read. Notice that the valve is in the same position for each test (ICK), but that the injection gas flow rate (MCFDI) varies from 814 to 1019. This is due to changing conditions (P1 and P2) around the Merla valve. Note that these are snapshots a month or more apart, but if you trend this for 1 day you’ll see the same effect. Flow rates can change drastically over a few seconds when something happens in the gas supply line (like a compressor shut down, a valve opening, etc.). Notice also that the Barrels of oil varies wildly as well. This is mainly due to surging (intermittent flow) from varying gas injection rates.

Well 2 Same type of data for a second well.

Manual valve data Well 2 Date BOPD MCFDI ICK 1-Sept-00 242 442 12 9-Feb-00 100 284 17-Nov-99 369 706 25-Mar-99 293 744 Notice that gas flow rates go from 284 to 744 with the valve never changing position. Oil flow rates are all over the map as well.

Well 3 Same type of data for third well.

Manual valve data Well 3 Date BOPD MCFDI ICK 10-Jun-00 907 1620 15 20-Apr-00 1193 1349 17-Nov-99 1072 992 16-Oct-99 635 1471 Same type of data for third well.

Manual Valve This shows how the injection gas rate varies from day to day.

Manual Valve This is the resulting oil production rate.

Manual Valve This shows the tubing pressure over a 3 hour time period. Notice the spikes. Spikes indicate surging.

Automation Advantages Stabilize gas flow rates Stabilize casing pressure Stop surging Eliminates intermittent flow Use gas where most needed Maintain optimal flow rate Increase overall production

Automation Alternatives Conventional Control Valve Orifice Plate, manifold, DP cell, Transmitter Meter run of pipe required (approx. 9’) Controller StarPac integrated solution

Conventional Automation Note the 9 foot meter run, not to mention you have to turn a 180 to come back and tie in to the original line. 9’

Conventional System Challenges Meter run of pipe required (space and weight) Plugging impulse lines on DP Slow update rate on controller (may see some flow variation) Installation and tuning time Installation cost Required infrastructure

Conventional System Installed Cost per well 2” Control Valve = $1,500 dp/manifold/orifice/flanges/transmitter/etc. = $3,800 Assumes compensated Local controller/DCS/PLC/flow computer $1,200 SI time 4 hrs at $100/hr = $400 Wiring = $400 Piping Modifications + Engineering = $8,000 Labor 24 hrs at $65/hr = $1,560 Lost Production (500 BOPD 6hrs + 100 BOPD 7 days)= $41,175 Total Installed Cost = $58,035 The big cost in this analysis is the lost production. First you shut the well in for about 6 hours (no production), then it takes up to a week to get all the instruments ranged, and the system set to run at the previously measured optimal flow rate. During that week you’re losing up to 20% of your potential production. In addition, putting a conventional system in takes 14-16 weeks from the time you cut the PO’s for the equipment. StarPac can be installed and running in 6 weeks.

StarPac Integrated Solution StarPac works like a variable orifice plate. As the valve strokes, the size of the orifice and the discharge coefficient changes. All of this data is measured in our lab, and stored on board in the electronics. We also store the fluid properties on board. By knowing the valve position we then know the coefficients and can calculate mass flow. The system includes a sensor for upstream and downstream pressure, and a thermocouple for temperature compensation. The flow is so dominated by the valve body, that we don’t need a straight run of pipe to have consistent measurements.

StarPac Integrated Solution Advantages No meter run required (saves space and weight) .25% Repeatability (30:1 rangeability) Fast update rate (16*/sec, no flow variation) Fully instruments line (inlet and outlet pressures, temp, flow, dp) data easily accessible + online storage Compensated Flow (press and temp) Benefits realized much sooner ($$$) Easy installation No sensor plugging System diagnostics & Process diagnostics StarPac can bolt right in where the Merla valve was in most cases. Things to watch for: The Merla is an API valve, but the face to face and bolt hole pattern is very close to ANSI. On some applications we’ve found that we’re 1/8 inch shorter, but the piping generally has enough play that it bolts in with no problem. In any event, we take a lot less space than the conventional automation alternative.

Installed StarPac These StarPac’s are on a platform in the gulf. The point of the picture is to show the tight confines you can put them in. Notice elbows on both sides of the StarPac. These happen to be StarPac 1 units.

Installed StarPac Cost per well Labor 8hrs at $65/hr = $520 Wiring = $200 Piping Modifications = $0 Lost Production = $0 - (run in bypass) Total Installed Cost $15,720 Note: additional savings for multiple installations (multi-drop) Typically, on bolt in applications, the well operates on bypass while the StarPac is installed. This eliminates the lost production. In addition, there’s nothing to range. Just use the keypad, type in the desired flow rate, and you’re running at the best known flow rate the instant you go off bypass. That gives you time to play around with connecting to the SCADA, DCS, PLC and sending set points remotely as you get it set up. The price listed is net price for a 2” 600 class carbon steel StarPac II, with a DP cell and offshore paint.

Space and Weight Requirements vs Manual System for 1 well StarPac Weight = +20 Space addition L 0 W +8” H +16” Conventional Automation Weight = + 120 Space addition vs manual L +108” W +12” H +16” Volume 12 cu ft Space and weight comparison.

Communication Options Local 4-20 Modbus Discrete (for interlocks) Most customers are moving toward remote operation, running several platforms from 1 central control point. This generally requires the use of SCADA systems (microwave transmission with RTU’s). Since we speak modbus, it’s relatively simple to map modbus registers to pass all of the data to and from the SCADA. The discrete inputs can be used for safety interlocks.

RS-485 4-20 mA Serial digital Communication (RS-485) 24 VDC Power Discrete Digital Signals Secondary Input (2) Output (2) Input (1) Electrical Pneumatic Mechanical This shows all the communication inputs and outputs.

Automation Options All data easily accessible Remote System Diagnostics Easy tie in to Master DCS/PLC/Laptop/SCADA/microwave Remote software for well testing Can design system for automatic testing Complete gas injection data Injection gas press/temp Casing pressure Mass Flow rate Valve Position On board data logging

Utilities Power Requirements Actuation Options 24VDC @ 300 mA Solar Cell and Batteries In line water turbine Actuation Options Pneumatic Air regulated to 150 PSI Max Gas regulated to 150 PSI Max Electro -Hydraulic Electric Often the user doesn’t have power. We have used solar cells, or an in line water turbine in the water injection line that charges batteries that power StarPac. You can also use a thermal generator which operates on gas. If using gas for actuation, they are typically taking a pressure drop from 1200 psi to 100 psi to supply gas to the actuator. Icing will be a problem if you do not use a regulator designed to eliminate icing, or use 2-3 regulators in series to take smaller pressure drops.

Limitations If dp too low (less than 10% P1) need to use dp cell If changing down hole valves, size to allow dp Flow accuracy is 10% of reading or 2% full scale (whichever is better) Installed system accuracy Cannot be used for custody transfer (if buying gas) May need 1 meter run and orifice for manifold gas line Repeatability is all that’s needed for control Required Infrastructure** If you are automating a manual system, you may not be changing the down hole gas lift valves; though it never hurts to ask. If you are resizing them, have them design them to operate at lower casing pressures. This allows us to take more pressure drop in the StarPac so we don’t need a DP (differential pressure) cell. Adding a DP cell adds cost to the total package price. Don’t get hung up on accuracy. Unless you are buying the gas from someone else, accuracy doesn’t matter….repeatability (being able to hit the optimal point and get the most oil out of the well) is the issue. If you are buying gas, you should meter it in the main header line, and still use the StarPac for control.

Installed System Accuracy Conventional Integrated VS We’ve seen cases where someone has changed the size of the orifice plate, and never made the change in the flow computer. We’ve also seen instruments waaaay out of range (I.e. orifice too large to measure the flow). You often don’t really know the installed accuracy of your conventional system. The accuracy we quote for StarPac is installed system accuracy…a number not actually known for a conventional system. StarPac can operate over a 30:1 range ability, so if you don’t know your process conditions, you’ll likely be OK anyway.

Accuracy and Repeatability “In matters of process control, precision and repeatability are more important than accuracy.” ISA Fundamentals of process control Theory”, 3rd Edition, Paul W. Murrill, page 89

Well 1 No Surging! Same well Data as before for the first well, after StarPac was installed. I wish we had 3-4 months more data with StarPac, but for now this is all we have for these wells. Notice that we’re injecting less gas, and getting more oil. Also we’re getting less %water. This is due to less well surging.

Well 2 Here we set the gas rate on the high side to see if they could get this poor well to put out some oil. The production came up a little, but not as much as hoped for. You can see that they have since reduced the gas injection rate to 550, and will test again.

Well 3 On this well we’ve reduced the rate to the low side, and production hasn’t suffered at all. Net effect is we are saving 600 thousand standard cubic feet per day of gas. We’re still optimizing this one as well.

Flow Control Comparison This compares response time of StarPac with an orifice plate (Masoneilan) and a vortex flow meter (Fisher). All of these systems were on the same flow loop and saw the same upset at the same time. Notice that when there is an upset, the StarPac is back to set point (red line) before the other devices have seen the deviation. This is because we calculate the PID loop 16 times per second. On a platform, if you are controlling in the PLC or DCS (or via SCADA) you will typically calculate every 2-3 seconds (or slower). This may not be fast enough to stop all of the surging. StarPac will.

StarPac vs Manual Gas lift Here’s a before and after comparison on gas injection rate.

StarPac vs Manual Gas lift Before and after on Oil production.

StarPac vs Manual Gas lift Before and after tubing pressure.

Project Summary 3 well upgrade Installation time 8 hours per unit Installation cost $47,160 (includes lost production) Increased overall production by 465 BOPD Used 200 MCFDI less gas Oil increase of $11,625 / day (@$25/bbl) Pay-back in 4 days Annual Revenue Increase $4,195,965 This is an economic summary of the results on the combined three wells.