Centrilift Improving Deepwater Production through Subsea ESP Booster Systems By Peter Lawson, Ignacio Martinez and Kathy Shirley, Centrilift echnology advances have made it possible for oil and gas operators to successfully explore Tin ultra deepwater. As these discoveries enter the production phase, new technologies are required to economically bring these deepwater reserves to market. Many of the production systems traditionally used in subsea applications in water depths less than 1,000 ft with moderate stepouts are not applicable for fields in significantly deeper waters where longer stepouts are necessary. Consequently, service companies and operators are searching for cost effective methods to produce these reserves over the life of the fields. Baker Hughes Centrilift is focusing 58 on innovative production systems to eco- nomically boost fluids from deepwater sub- sea fields. These solutions employ electrical submersible pumping (ESP) systems either downhole or on the seabed. Gas Lift Limitations Where gas is in abundant supply, gas lift has traditionally been the preferred artifi- cial lift method in subsea applications with relatively short stepouts. However, gas lift poses certain technical and economic challenges for new discoveries in deeper waters where high fluid volumes per well are required to justify the costly development infrastructure. Also, in situations where several small deepwater fields are produced to a single host production platform, longer stepouts are required, which makes gas lift an ineffi- cient artificial lift option beyond 10 to 15 km (6.2 to 9.3 mi.). In addition, gas lift systems require large surface facilities to compress the gas. The space and weight requirements of these compression facilities are often just not feasible on deepwater floating production platforms. ESP Technology ESP technology is an ideal solution to pro- duce significantly higher fluid volumes and provide the necessary boost to deliver the production stream to the host platform. Providing electricity to the ESP systems is less complex and more efficient than delivering gas for gas lift systems. The high volume capacity, wide operating range and efficiencies up to 40% higher than gas lift make ESP systems more attractive for deepwater subsea wells. Traditionally, ESP systems are installed downhole. Centrilift has installed ESP Figure 1. In-well ESP installations systems in multiple subsea wells in the North Sea as well as offshore Australia all reserve recovery, but in very deep and Brazil (Figure 1). waters in-well systems are extremely expensive to install and replace when they Seabed Boosters wear out. The seabed booster concept is While these in-well systems have operated a compromise that provides some boost effectively, intervention costs are a con- without the enormous capital costs of stant concern. Centrilift is working to in-well installation and intervention. develop seabed booster systems to give Most subsea wells will flow naturally to operators more options for economic pro- the production facility for a period of time; duction systems. It is always best to install however, as the reservoir pressure declines the artificial lift pumping system as close to to a point where the well can no longer the reservoir as possible to maximize over- produce to the host platform, the well will 59 Centrilift Improving Deepwater Production through Subsea ESP Booster Systems completely shut down – even though the the systems, which also significantly reservoir may still have sufficient pressure reduces overall development costs. to produce to the seafloor. This situation Seabed ESP booster systems are not as leaves significant oil in place that can be space constricted as in-well systems. captured with seabed booster systems. Even when the reservoir pressure further Production from several wells can be declines and requires in-well systems, the boosted with only one seabed ESP seabed booster equipment allows opera- booster system. tors to install smaller horsepower ESPs in Not all subsea wells are good candi- the well, which generally enhances system dates for ESP booster systems. The primary run life. technical considerations are intake fluid In recent years, a number of attempts conditions, including intake pressure, free have been made to deploy traditional gas, declining reservoir pressures, increased surface multi-phase pump systems, which water cut and flow assurance. The capacity have been “marinized” onto the seafloor. to produce free gas is, in part, a function However, these systems are complex of pressure. The higher the pressure, the and costly, often requiring constant more gas the pump can handle. If intake lubrication oil feed and have experienced pressure is above 1,000 psi (68.9 bar), some early technical problems with the multi-phase ESP systems can handle up sealing systems. to 70% free gas; at 500 psi (34.5 bar) the systems may only be able to produce 50% ESP Advantages free gas; and if pressures drop to 200 psi Currently, Centrilift standard ESP systems (13.8 bar) more than 30% free gas can be have higher pressure boost capabilities an issue. Free gas percentages are typically than most of these traditional surface higher at the seabed vs. downhole because systems. Plus, ESP systems by their very pressures are lower. design are intended to be immersed in fluid and it doesn't matter if that is in the Multi-phase Pump Stage well or on the seabed. ESP motors are Centrilift has designed a specialty multi- pressure balanced with the environment, phase pump stage specifically for produc- whether that is downhole pressures or ing gas-laden fluids. Free gas impacts water pressures in subsea applications. pump efficiency, but multi-phase pump Basically, ESP systems are designed for the stages improve efficiency over typical subsea environment, unlike traditional sur- stages when producing high percentages face pumps that must be re-engineered to of free gas. Gas separators, which are com- overcome pressure and penetration issues. mon in downhole systems, could also be The first issue for any field develop- applied to seabed applications; however ment is economics and ESP seabed booster separate gas risers would be needed to systems offer several advantages over transport the separated gas. For the future, other alternatives: the industry is studying seabed gas com- Seabed ESP systems can be deployed pression systems, which would allow opera- with vessels of opportunity vs. semi- tors to re-inject the gas for reservoir submersible rigs, reducing both the pressure maintenance. overall cost of installation and inter- Another critical concern when consider- vention and deferred production ing a seabed ESP boosting system is reser- resulting from a waiting period for voir pressure decline and increasing water a rig. cut. Accurate reservoir pressure decline curves over the life of the well are critical. Seabed ESP systems can be If the reservoir pressure declines too quick- configured to provide a back up ly, the well will not flow naturally to the system to maximize run life and seafloor long enough to justify the eco- minimize deferred production. nomics of the booster system. Water cut Some seabed ESP system alternatives also factors into this decision. Increasing use existing infrastructure to house water cut requires more pressure to flow 60 fluids to the seabed, so even if reservoir ed because of viscous shear and, conse- pressure remains static the well can stop quently, the sizes of the stage hydraulic flowing. These scenarios may require oper- passages are diminished. It then becomes ators to consider in-well ESP systems to necessary to oversize the hydraulic capacity provide artificial lift. of the pump stage for a specified flow rate to compensate for the reduced capacity. Flow Assurance Issues If the viscosity of the fluid is high Flow assurance is a concern in virtually enough due to seabed temperature after any seafloor installation and ESP booster a system shut down, there are increasing systems are no exception. Fluid viscosity, chances of a hard start or even the pump hydrates and gas slugs are the primary shaft locking. Lab analysis has demonstrat- flow inhibitors in ESP seabed systems. ed that the shaft can be locked with Under stable conditions, the intake tem- viscosities above 5,000 to 8,000 centipoises perature on the seabed is close to the (cP). To eliminate this concern, methods reservoir temperature and flow assurance to displace the viscous slug from the issues are minimal. However, if the ESP pump or reduce viscosity before start up equipment is shut down for any period of is necessary. time the fluid in the seabed system will The standard Centrilift CenturionTM cool to the seawater temperature. This sit- pump line design does address friction loss uation can be detrimental to the ESP if the to minimize the impact of viscous fluids system design does not account for fluctu- and also includes specialty pump designs ating fluid volumes created by tempera- for extremely viscous fluids. ESP systems ture expansion and contractions due to are a valid artificial lift method in medium- increasing fluid viscosity and possible to-high viscous fluids. With special viscous hydrate formation at lower temperatures. fluid handling designs, ESP performance is Hydrate formation is another issue for further improved. ESP seabed booster systems. Hydrates can plug flow lines and damage production Gas Slugs equipment. Techniques to control or avoid Another concern for seabed installations formation of hydrates fall in two cate- is gas slugs, which significantly impact gories: physical or chemical. Physical meth- pump efficiency. Slugs are more likely in ods are heated flow lines and/or ESP applications with longer stepouts from the systems and insulated flow lines. Chemical wellhead to the booster system, high vis- inhibitors include thermodynamic cosities, low fluid velocities and flow lines inhibitors (the most common solution) and that follow undulations of the seafloor. anti-agglomerate and kinetic low dose hydrate inhibitors. Anti-agglomerants are Flow Loop Testing recommended for ESP shut down periods.