Case Studies - PTTC Rockies

Treatment Design

Preflush

A preflush is recommended to clear the tubulars of any contaminants that may adversely affect the polymer cross-linking chemistry. Acid preflush should be used to clean out solids in the wellbore. The solids should then be circulated back up. Rust, divalent ions, and hydrogen sulfide can cause chemistry problems with the polymer gel and cross linker. Three tubular volumes of clean mix water are recommended as a preflush.

Polymer Concentration

Since polymer concentration should be a function of fracture aperture, and fracture aperture is difficult to measure, experience and analogy becomes the design method. Treatments performed by Marathon in the Big Horn Basin were done on wells with very similar production characteristics. The perforated interval, and total fluid production rates were similar. Reservoir temperature and pressure were slightly lower. Therefore, the Teapot Tensleep fracture apertures are assumed to be close, but slightly smaller than those in the Big Horn Basin Fields. There, 90% of the treatment is 5,000 ppm and 10% is 8,000 ppm is found to be optimum. This same design will be used as a starting point for the Teapot Tensleep treatments. A small amount of 3,000 ppm could be used up front just to test injectivity.

Treatment Volume

Based on Marathon’s experiences in the Big Horn Basin, a treatment volume based on 25 bbls per foot of perforated interval seems to be a prudent starting point. This number should be adjusted since the well spacing on the Big Horn Basin treatments was 5 acres and the Teapot Tensleep wells are 10 to 20 acre spacing. If 50 bbls per foot were used, a 2500 bbl treatment would be an appropriate volume for the first treatment.

Treatment Rate and Pressure

Based on the experience by Kinzele (1998), it is very important to place the gel as deep as possible into only the largest fractures. Seright (1998, 2000) shows how gel dehydration affects gel placement. Dehydration is a function of time and pressure. Both of these variables should be minimized. Consequently, the rate should be maximized at a reasonable pressure. The estimated fracture initiation pressure is 3,180 psi (885 psi surface pressure). In no case should this be exceeded. It is recommended to treat the well at the maximum rate possible at a bottom hole treating pressure of 3100 psi. Surface pressure can be increased to account for friction pressure loss in the tubing during treatment. During the displacement, rate will be maintained to prevent the pressure drop due to reduced friction from causing a fracture.

Displacement

In order to improve the chances of an economic oil production rate following the treatment, an over displacement should be considered. Experience in the Big Horn Basin is to use plain water as the displacement fluid and pumping two wellbore volumes to accomplish slight overdisplacement. Portwood (1998) suggests a displacement with a cationically charged polymer. Since the polymer used for shutoff and the rock both carry anionic charges, any polymer that tends to flow back during production will be held to the rock by the cationic polymer. The work of Seright (1998, 2000) indicates that by the end of the job, gel dehydration occurs and the newly injected gelant wormholes through the dehydrated gel. This could explain why little effect was seen by Kinzele (1997) when different fluids were used as displacement. Since fingering occurs anyway because of dehydration, a mobility controlled displacement fluid is ineffective. Likewise, the cationic polymer does not get the chance to bond anionic polymer to rock, since it is very difficult to contact the rock with the dehydrated gel on the fracture face.

Quality Control and Data Collection Program

A pressure buildup test is highly recommended before and after the treatment to benchmark the volumes and success against fracture volume and skin calculations. It also helps to characterize the reservoir and production mechanisms.

Laboratory tests should be run with the recommended polymer system and the Tensleep produced water to be used for treatment. Gelation time and gelant viscosity should be measured for job design. Gelant viscosity can also be measured and used to get a ballpark estimate of friction pressure in the tubing during the treatment.

Checks of the actual materials and water should be run the day before the job.

The following items should be monitored continuously during the job and recorded as a function of time:

Injection rate
Cumulative Injection Volume
Injection pressure
Polymer Composition
Polymer Concentration
Cross linker Composition
Cross linker Concentration
Feed water Temperature
Sample gelant at wellhead using two-valve sampler to prevent shearing and measure viscosity.

A Hall plot should be done in real time to diagnose the treatment progression.

Figure 6.

Figure 7.

Figure 8.

Figure 9.

Treatment Procedure

Prepare for Treatment
- Test gel formulation and chemistry in the laboratory with actual water and chemicals to be used during the test.
- Measure well production rate, fluid level at stabilized production rate.
- Perform overnight pressure buildup test.
- Test anchors.
- Set 1000 bbl tank. Lay temporary flowline and use yellow dog pump to fill with cool Tensleep water from lower discharge pit. Have 2" NPT outlets. Continue to refill tank as treatment starts to provide a total volume of +/-3500 bbls water.
- Rig up 125 KW generator and diesel tank. Fill diesel tank with 650 gallons.
- MIRU workover unit and haul in 5500 foot 2 7/8" work string.
Pull Well
- Kill well with 225 bbls 9.7 ppg salt water.
- RU BOP's
- Rig up spool truck.
- Pull well setting, and lay down large tubing.
- Pick up work string.
Stimulate Well
- Rig up stimulation services.
- Stimulate well with propellant treatment.
Prepare for Gel Treatment
- Run Baker Retrievamatic packer and 2 7/8" tubing. Put 2 7/8" x 2" NPT crossover on surface.
- Set packer +/- 5367' with minimum 20,000# compression. The collars are at 5184', 5182', 5222', 5261', 5305', and 5348'.
- Test backside to 500 psi, shut-in with pressure. Install gauge to monitor.
- Rig up polymer mixing and pumping equipment.
- Check equipment function. Establish injection rate with at least 317 bbls preflush.
Pump Gel Treatment
- Shut-in offset Tensleep production wells when treatment starts.
- Prepare to monitor:
- Pump 700 bbls cool water to cool tubulars, near wellbore area at 1 BPM.
- Pump 2250 bbls 5,000 ppm polymer and cross linker at <800 psi.
- Pump 250 bbls 8,000 ppm polymer and cross linker at <800 psi.
- Flush with 317 bbls water at same rate.
- Shut-in well for 72 hours.
- Return offset wells to production.
Return Well to Production
- Swab well until fluid is free of polymer.
- Unseat packer and POOH.
- Run electric submersible pump with intake at approximately 5400'.
- Return to production, monitoring fluid level and adjusting pump speed with VSD.
After production has stabilized for two weeks, run follow-up pressure buildup test.

Table 5 Reservoir Properties used to predict performance after treatment.

	Before		After
Average Permeability	8	md	8	md
Relative Permeability	0.8		0.8
Net Thickness	75	ft	75	ft
Avg Reservoir Pressure	2450	psi	2450	psi
Depth to perfs	5397	ft	5400	ft
Fluid gradient	0.433	psi/ft	0.005	psi/ft
Fluid level above perfs	500	ft
Wellhead pressure	200	psi	100	psi
Flowing bottomhole pressure	416.5	psi	127	psi
Viscosity	1	cp	1.5	cp
Formation volume factor	1	RB/STB	1	RB/STB
Drainage radius	330	ft	330	ft
Casing size	7	in	7	in
Skin factor	-5.53		-4.53
Flow rate	6902	BPD	2630	BPD

The oil production rate was forecasted assuming that the well would retain the same inflow performance relationship following the treatment as it had prior to the treatment in a pumped off condition. This rate was calculated using a linear inflow performance relationship to calculate the total fluid production rate at a pumped off condition prior to the treatment. The productivity index for the well was determined to be 3 BFPD per psi of drawdown. The calculated AOF is then 7,350 BFPD. Using a statistical correlation for the oil cut as a function of total fluid production rate (Figure 2), the oil cut at AOF is projected to be 0.0028. Multiplying the oil cut by the AOF calculation predicts that the well would be able to produce 20.5 BOPD following the treatment. It is assumed that the 35% nominal decline rate existing prior to the treatment would continue after the treatment.

Figure 10.

Economic Analysis

Incremental Net Present Value analysis was done to evaluate the benefits of the project. Based on the current water handling cost of $0.02 for lifting and $0.01 for surface handling, a savings of $0.03 per barrel was used for projected shut-off water. All production was risked at 75%. No inflation was used. At a discount rate of 10% and an oil price of $20 per barrel, the project has an incremental net present value of $353,170 over the current operating conditions. It is expected to pay out in 0.6 years and yield an internal rate of return of 189%.

Logistics

It takes quite a bit of time to thoroughly analyze well performance and to understand problem water production well enough to design an effective shut-off treatment. Once the design is completed, several service companies should be contacted to provide proposals for the job. There is quite a bit of variation in pricing to perform the services.

A project schedule is included in the appendix of this manual to aid in planning similar jobs.

A considerable volume of water is required to treat a well. Careful consideration should be given to selecting a clean consistent source of water and to storing the water on location prior to the treatment. Crosslinking is sensitive to iron, and precautions should be taken to minimize the exposure of the water to iron and to sulfides. For this job, the water source was the NPDES discharge point for the field-produced water. This site was relatively close to the well to be treated, so a flowline was laid from the discharge pit to the location. Seven 400-bbls swab tanks were set on location. A gasoline-powered Yellow Dog pump was used to fill the tanks from the pit. The tanks were expected to be refilled as the treatment progressed, eliminating the need for additional tanks.

A source of power is required to mix and pump chemical. In this particular job, 125 KW are needed. A diesel generator was used to provide electrical power. The Caterpillar 3406 engine consumes approximately 13.5 gallons of fuel per hour, necessitating a bulk diesel tank be set on location.

Polymer gel pumping was scheduled to occur over a weekend, since the rig was to be left on location during the job.

Schedule

A copy of the schedule is included at the end of this report to give an idea of the activities that are included in this project, the resources required to accomplish the work, the duration of all of the activities and breakdown of cost by activity. This schedule is the planning schedule for the project and may change substantially to reflect actual occurrences.

Post-Treatment Artificial Lift System

When one changes the production rate drastically, the artificial lift system needs to be redesigned. This is especially true if an electrical submersible pump system is being used. The well will go from maintaining a relatively high fluid level to being pumped off if the treatment is successful. By this time, the uncertainty of post treatment production rates should be understood. This further compounds the planning for a lift system after the treatment.

In this instance, the ESP system is controlled by a variable speed drive. The pump may be run deeper into the well after completion, requiring additional cable to be run. This means that a splice may be required, as well as additional tubing. The fluid rates will be lower, but a higher pump head will be required. Therefore, the number of stages in the pump may be inadequate. The lower fluid volume means less horsepower will be required, so the motor should be adequate. It will be turned at lower frequency to match the well’s inflow. The pump should not be expected to perform under these new conditions. But it may be able to function long enough to reveal the well’s new inflow performance relationship.

Once the new IPR curve is determined, another pump designed for the well’s new attributes will be run. This new pump equipment is expected to be available from another well in the field. Since there are several Tensleep wells producing, the equipment will be rearranged to best fit the producing wells. This will minimize the expenditure on new equipment.

Alternatively, a temporary unit could be rented from a pump supplier to test the well prior to installation of new equipment.

If the well inflow is significantly reduced, a rod pump system may be considered. Generally, this would only be economic if total fluid production drops to less than 1500 BPD

Before