Artificial Lift Methods and Constraints
Artificial lift is widely used in the shallow water of the Gulf of Mexico, but its use in deepwater (>1,000 ft) is limited. However, most deepwater oil fields ultimately require the artificial lift to maintain the production flow and achieve economic objectives. Planning for an artificial lift in deepwater is critical, as the environment is operationally more difficult and economically more challenging. The following are the main artificial lift methods:
- Gas Lift (GL);
- Subsea Boosting;
- Electrical submersible pumping (ESP).
Gas Lift
Gas lift (GL) is a predominant artificial lift method used in the offshore environment to date; however, as operators progressively move into deepwater, GL applications become more limited due to higher operating pressures and ESPs applications become more suitable. The selection and determination of the gas lift system depends on:
- High water cut of the reservoir;
- Low GOR of the reservoir;
- Long offset flowline;
- etc.
The designs of gas lift for subsea wells have several requirements that are not normally encountered in the designs of traditional gas lift. First, the cost of intervention in a subsea well is considerably higher than for a traditional completion, the subsurface gas lift equipment must be designed with special attention in reliability and longevity. Secondly, the sizing of the port in the operating valve must anticipate production conditions for the life of the well.
The design of gas lift system involves two key parameters: gas lift volume and gas lift pressure. Gas lift volume is the total requirement for the field determined by individual well requirements. Production will increase as a function of lift gas volume until a point of maximum production is reached. Gas lift pressure should be determined carefully since this parameter will influence the system operating pressure, material and equipment specification of the well system.
Subsea Pressure Boosting
Some reservoirs have sufficient pressure to push the production fluid from the reservoir to the platform without the use of downhole artificial lift.
However, due to the reduction of the reservoir pressure after a long time production, or because of ultra-deepwater light-oil and deepwater heavyoil
reservoirs having pressure that is near hydrostatic pressure, it is quite difficult to produce the fluids to the sea surface. Subsea boosting reduces or eliminates the backpressure on the wells resulting from the riser hydrostatic head and the riser and flowline pressure drop caused by high viscosity. The pressure increase between the output of the boosting and the backpressure on the well will increase the flow from the well. Components of a subsea boosting station may include:
- Subsea gas compressor, normally used for gas re-injection into the reservoir for pressure maintenance;
- Subsea multiphase pump, used for reduce the back-pressure on wellheads thus increase the transport distance;
- Subsea wet gas compressors, used for gas transportation to remote offshore host facilities or onshore factory;
Subsea boosting may require high consumption of the electric power during the production thus the power sources should be considered. Subsea pressure boosting system enables longer subsea tiebacks, which potentially could enable the economics of exploiting small, remote, marginal fields. Subsea separation could provide an economic alternative for debottlenecking existing surface process facilities, allowing better utilization of these installations by adding new subsea tiebacks which currently would not be economic to develop. Subsea gas separation may allow oil and gas to be separated at the seabed and be transported to different production facilities, which may solve flow assurance problem due to low temperature at seabed.
Electric Submersible Pump (ESP)
Due to the reduction of the driving force which lifts the reservoir from downhole naturally, pumps were commonly used to increase the backpressure for production. The electric submersible pump (ESP) is an effective and economical method of lifting large volume of the fluids from downhole under different well conditions. ESP system requires a large electricity supply, but it is less complex and more efficient than delivering gas to gas lift systems. An ESP system may include following components:
- Three phase electric motor;
- Seal assembly;
- Rotary gas separator;
- Multi-stage centrifugal pump;
- Electrical power cable;
- Motor controller;
- Transformers.
Different from the surface pump system, the ESP systems are particularly designed to be immersed in fluid. It can be either located in a well or on the seabed. The ESP motors are pressure balanced with the environment, whether that is downhole pressure or water pressure in subsea conditions. Optional components of the ESP system may include tubing joints, check valve, drain valve, downhole pressure and temperature transmitters, etc. The selection of ESP types mainly depends on the well fluid properties. Following are the three major types of ESP applications:
- High water-cut wells producing fresh water or brine;
- Multi-phase flow well with high GOR;
- Highly viscous fluid Well.
The pump rate is a function of the rotational speed, the number of stages, the dynamic head acting against the ESP and the pumped fluid viscosity. These factors dictate the differential pressure across a pump system, and therefore the flow rate. However, for a given pump, there is an optimal design flow rate that maximizes pump efficiency and run life. Sizing of ESP is based on predicted completion performance, or flow rate. This usually involves examination of the well inflow performance relationship (IPR), which describes the production response to changes in bottomhole pressure (BHP). Data required for calculation and sizing of ESP includes well data, production data, well fluid conditions, power sources and possible problems etc. Calculations for designing an ESP system include:
- Determination of Pump Intake Pressure;
- Calculation of total dynamic head ;
- Selection of pump type;
- Check of load limits;
- Selection of accessory and optional equipments.
References
[1] C. Claire, L. Frank, Design Challenges of Deepwater Dry Tree Riser Systems for Different Vessel Types, ISOPE Conference, Cupertino, 2003.
[2] M. Faulk, FMC ManTIS (Manifolds & Tie-in Systems), SUT Subsea Awareness Course, Houston, 2008.
[3] R. Eriksen, et al., Performance Evaluation of Ormen Lange Subsea Compression Concepts, Offshore, May 2006.
[4] CITEPH, Long Tie-Back Development, Saipem, 2008.
[5] R. Sturgis, Floating Production System Review, SUT Subsea Awareness Course, Houston, 2008.
[6] Y. Tang, R. Blais, Z. Schmidt, Transient Dynamic Characteristics of Gas-lift unloading Process, SPE 38814, 1997.
[7] DEEPSTAR, The State of Art of Subsea Processing, Part A, Stress Engineering Services (2003).
[8] P. Lawson, I. Martinez, K. Shirley, Improving Deepwater Production through Subsea ESP Booster Systems, inDepth, The Baker Hughes Technology Magazine, vol. 13 (No 1) (2004).
[9] G. Mogseth, M. Stinessen, Subsea Processing as Field Development Enabler, FMC, Kongsberg Subsea, Deep Offshore Technology Conference and Exhibition, New Orleans, 2004.
[10] S.L. Scott, D. Devegowda, A.M. Martin, Assessment of Subsea Production & Well Systems, Department of Petroleum Engineering, Texas A&M University, Project 424 of MMS, 2004.
[11] International Standards Organization, Petroleum and Natural Gas Industries-Design and Operation of the Subsea Production Systems, Part 1: General Requirements and Recommendations, ISO 13628-1, 2005.
[12] O. Jahnsen, G. Homstvedt, G.I. Olsen, Deepwater Multiphase Pumping System, DOT International Conference & Exhibition, Parc Chanot, France, 2003.
