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Heavy oil deepwater well testing with riser requires an engineered solution involving an electric submersible progressing cavity pump (ESPCP).
A large part of the exploration investment for many major oil companies is dedicated to deep and ultradeepwater reservoirs. Operators targeting these deepwater reserves are constantly searching for ways to optimize extraction of heavier grade crude (less than 15° API) to reduce well testing costs. Determining the economic viability of a given reservoir presents operators with a number of challenges including low reservoir pressure and temperature, low gas/oil ratios, and high fluid viscosities. Because these difficult well conditions are often accompanied by logistical and cost issues, some form of reliable artificial lift must be employed to obtain uncontaminated fluid samples and a stable drawdown. With these factors in mind, deepwater testing has been conducted off the Brazilian coast using a riser reservoir-deployed ESPCP in place of a conventionally deployed electric submersible pump (ESP) system.
To adequately evaluate the economics of a given well, constant fluid production must be maintained. This enables the operator to determine the effects of drawdown on the reservoir as a whole and to obtain samples of the reservoir fluid in situ. Conventional testing methods using nitrogen and coiled tubing may not be capable of providing sufficient lift to overcome the effect of low temperatures on heavier API crudes. Other testing methods do not take advantage of the three principle deepwater benefits:
Water depth comprises a substantial percentage of the reservoir depth.
Riser sizes are generally large enough to accommodate "big bore" systems
The reservoir static pressure as measured at the mudline (Datum) is generally high enough for effective drawdown.
Conventional ESP well test systems
The effectiveness of ESPs for offshore well testing has been established worldwide. When combined with a variable speed controller, an ESP has the ability to make instantaneous changes over a wide range of production rates to keep a constant drawdown pressure on the reservoir. Additionally, it can be combined with a number of sensors (temperature, pressure, flow, etc.) to provide accurate real-time reservoir data. An ESP can also be used in conjunction with a bypass system to allow access to the perforated interval to perform interventions (wireline work, spotting acids, etc.) without pulling the pump from the hole.
The space-outs between the subsurface test tree (SSTT), blowout preventer (BOP) can, fluted hanger, and the packer are critical to environmental containment of the lower wellbore. They also support the string so that it can be fished in the event of an emergency disconnect of the SSTT. Because of close lateral tolerances between the test string and the casing, key areas for potential equipment damage during deployment center around the electrical penetration through the packer, the electrical penetration in the BOP can, and the area of the cable surrounding the outside of the SSTT.
Testing from a floating platform in heavy seas increases the possibility of damage resulting from unpredictable movement between the riser, test string and platform. This possibility is compounded again due to the long riser lengths of up to 9,840 ft (3000 m). Additionally, conventional ESP test configurations have the following disadvantages:
Unless an expensive wet-mate system is used, an SSTT disconnect will require a complete pull of the ESP to reconnect the cable at the BOP can. The packer will also need to be redressed.
Installations are highly complex.
Deviated wells require equipment to be placed in a suitable tangent section.
It is necessary to use an ESP packer with electrical penetrators.
Riser deployed test system - RDTS
Recognizing the limitations of deepwater testing with a conventional ESP system, an alternative design was developed using an encapsulated ESPCP set in the riser just above the SSTT as part of the test string. This unit is intended for deployment in water depths of 3,280 ft (1,000 m) to 9,840 ft (3,000 m) and is capable of producing 500 to 1,000 b/d of 15° API crude or lower.
Deployment begins by setting a conventional production packer and sealbore at depth above the zone of interest. A bottomhole assembly (BHA) is then constructed using a seal assembly suitable for the production packer and a conventional test string with samplers, recirculation valves, etc., below the SSTT. The capsule is then assembled with the ESPCP inside, made up into the string above the SSTT, and tested to 5,000 psi to ensure pressure integrity.
The central string in the capsule also contains a sliding sleeve (conventional or hydraulic) which can be opened to either flow the well naturally or circulate fluid past the ESPCP. The capsule can also be constructed to accommodate a by-pass to allow wire line or coiled tubing intervention below the ESPCP. Fluid flows from the formation into the test string entering at the bottom of the capsule; it is then drawn into the pump intake and produced to the surface.
The immediate advantages of this configuration are elimination of the ESP packer, BOP can, and the associated electrical penetrations. Cross-collar cable protectors are also used to protect the cable in the riser from damaging movement between the riser and the rig during deployment. This installation is much simpler, quicker, and more reliable than a conventional ESP system.
Target sizing data
To ensure application over the widest possible array of wells, the unit was designed to accommodate a range of application conditions as shown in Table 1.
To operate in these disparate well conditions, a Centrilift LT 3000-2300 progressing cavity pump was selected with a design capacity of 503 b/d to 943 b/d (80 m3/d to 150 m3/d) at 2,300 psi discharge pressure. The LT 3000 was selected for its high-grade elastomer which is capable of withstanding the invasion of gas (swelling) that can occur under high GOR conditions.
It should be noted that in order to prevent system overheating, the lower rate was calculated based on the minimum velocity of fluid passing the motor. The actual minimum rate under any given set of conditions is determined by the fluid temperature encountered, thus lowering even further the minimum rate possible. Harmful downthrust loading due to low production, which can occur in standard ESP systems, is not an issue with ESPCP because these forces are absorbed by the seal section.
This system design also included a 76hp, 1360V, 36A, motor, a 538 gear reducer with a capacity of >1,300 ft/lb of torque, and a seal section with a 11/8-in. high strength shaft. A pressure/temperature sensor was included at the base of the ESPCP to provide real-time data. A secondary set of retrievable gauges was placed at the base of the test string near the perforations to provide back-up and redundancy.
Flow assurance concerns
Because the estimated mudline temperature was only 39?F (4?C) there were some valid concerns about the mobility of viscous fluids in the pipe. The first area of concern was in the test string between the mudline up to 984 ft (300 m) from the water's surface. Calculations indicated that low temperatures found at these depths could cause the fluid to solidify during periods of low or no flow (if the GOR was below 10). To mitigate this possibility, coiled tubing was run inside the test string to one joint above the ESPCP discharge. To ensure mobility, diluent (diesel) would be periodically mixed with the produced fluid.
The second area of concern was from the mudline down to a depth of 656 ft (200 m). Since temperatures at these depths are equal to the surrounding water temperature, the effects on the fluid would also be the same. Calculations indicated that the reservoir pressure would be sufficient to push the cooled fluid into the pump intake and that the ESPCP would be able to pass the fluid on to the upper test string. However, there was some doubt about the feasibility of accurately correlating pressure readings at the pump intake, due to increased friction or plugging of the cold fluid within the string below the mudline.
Well test installation
The first system test occurred on a well in 5,117 ft (1,560 m) of water. The installation of a standard ESP completion had been attempted several times but was never successfully accomplished due to repeated cable damage in the vicinity of the BOP can and riser.
The assembly of the ESPCP unit began with a 103/4-in. capsule. After assembling the capsule, the ESPCP was placed inside; cable splices made above and below the top cap and the unit was lowered to a depth of 5,018 ft (1,530 m) in the riser. The overall operation from start to finish required 40 hr of rig time and included a full function test of the system about half way in the hole. After landing the unit, the surface flow and electrical connections were made and the unit successfully started.
The results from the test, while disappointing from a reservoir perspective, were very successful in proving system viability. The results are shown in Table 2.
It should be noted that the PI was considerably lower than had been anticipated. This was probably due to skin damage caused by previous test attempts. The maximum sustainable rate that could be maintained was 126 b/d (20 m3/d). Even at this very low rate, the motor was properly cooled as a result of fluid temperatures that remained close to 80?F (28? C).
Pressure can be accurately calculated using standard methods. Although the API 11? fluid produced was consistently below 80?F (28?C) there was no indication that plugging or friction in the tubing string below the unit impeded reading accuracy.
Several attempts were made to run the unit without adding diluent above the pump intake. This resulted in a maximum system load of up to 135% of the design capacity. Therefore, diluent pumping was maintained at a ratio of 7:1. It should be noted that despite excessive loads there was no evidence of undue wear after system retrieval.
Test results indicate that a riser deployed ESPCP required less rig time for system deployment than a conventional ESP (even with a full function test half way in to the hole) and although conditions were radically different than expected, the ESPCP operated flawlessly. Other findings included:
Flow from below the pump was unaffected by the lower than expected temperatures encountered during testing.
Pressure correlations could be made within the accuracy range of the sensor
Diluent injection was required in the tubing string above the capsule
Tests also resulted in new capsule design that would allow for chemical stimulation of the reservoir while isolating the pump from excessively high pressures when circulating the tubing clean.