Subsea well artificial lift methods and seabed multiphase boosters are increasingly being used together to maintain production levels of mature offshore reservoirs and to allow economic development of marginal fields using tiebacks over longer distances to existing regional infrastructures located both on- and offshore. By combining subsea inwell lifting and seabed flow boosting - while incorporating total system engineering and strong project management - synergies are created between the two technologies, with strong drivers toward their more widespread use being deeper water and wells.

This article presents a case study that illustrates the productivity advantages arising from combining either a gas-lift or electric submersible pump (ESP) artificial lift technique with a seabed multiphase pump (MPP), with end-to-end pressure management from the sandface to the production facilities. Specifically, the study shows that supplementing subsea well artificial lift with a seabed multiphase booster permits a 15% increase in production compared to ESP use alone and a 38% increase compared to just gas lift. While combining systems presents operational challenges, the risk can be mitigated through careful system integration in the design phase. Additionally, risk can be further reduced by monitoring and controlling the entire system both in the wellbore and on the seabed.

As with most subsea applications, the need for real-time data and information is playing an increasingly important role to improve efficiency and run-life of well lifting and boosting systems designed for the subsea environment. Presented in the form of a hypothetical laboratory experiment, the study utilizes several inwell and seabed production instruments that are monitored and controlled using a new Subsea Monitoring & Control (SMC) platform from Schlumberger. The SMC platform provides the flexible monitoring and control capabilities needed to enhance real-time diagnostics and thus maximize reliability and performance of the integrated subsea system.

Inwell artificial lift

To maximize drawdown and total production, offshore oil wells are routinely completed with gas lift systems that operate within the limits of current injection pressure valve technology. However, as operators move toward deepwater and subsea producing environments, higher injection pressures and deeper depths of injection are required to effectively realize gas lift production potential. Traditional gas lift valve reliability is generally not a concern for dry tree applications because of low slick-line intervention costs. However, these intervention costs can be economically prohibitive for deep subsea well gas-lift completions where bellows operated valves are used. While the use of single point orifice valves can eliminate this risk, they may result in less than optimal subsea well completion and production.

New deepwater subsea high pressure gas-lift technology has recently been developed to minimize the risks associated with traditional bellows operated gas lift valves. Subsea high-pressure gas lift valves can improve project economics through increased production and enhanced reliability at higher pressures. Utilizing unique bellows technology, these valves can be set deeper in the well to provide additional drawdown and increased production, depending on the application. The new high-pressure gas lift technology rates reliable bellows operation for 5,000 psi at the valve depth, compared to the previous 2,500-psi limit typically present with traditional gas lift valves.

The use of fiber optics in subsea installations for monitoring reservoir performance and flow assurance in risers and flow lines also has proven to be an excellent way to determine the health of inwell artificial lift methods such as gas lift. Integration of a fiber optic distributive temperature sensor (DTS) across the surface-controlled gas lift valves can add considerable diagnostic capability in real time and aid in understanding the gas lift systems. The DTS and surface-controlled valve combination provides the domain expert with the data and flexibility needed to monitor completion component operations, detect failures and control gas lift settings.

In high water cut or low-pressure or solution gas (heavy crude) situations, gas lift may not be the suitable artificial lift method. While ESPs provide an artificial lift alternative, their high intervention costs associated with failures in subsea wells must be considered. A dual ESP system can be used to extend ESP life and minimize potential interrupted production by offering stand-by capability. Run life is extended provided the complexity of the dual system does not shorten operating life compared to a single pump installation and an effective pump monitoring and control system is in place. For situations where ESPs are deemed the best suited lifting method, an ESP is usually a more effective back-up than gas lift. Along with redundancy, dual systems allow the use of two different sized ESPs, which can provide flexibility in reservoirs that present uncertainty in future performance.

Integration with seabed MPPs

Long subsea tiebacks to host platforms have become a cost-effective solution for developing smaller, more marginal fields, and gas lift is often the preferred artificial lift method, provided gas is available. Although subsea high-pressure gas lift has been proven for deep wells and water depths, its effectiveness in long horizontal flowlines remains questionable. The inherent nature of the injected and liberated gas is to separate and hold to the top of the flowline, negatively affecting fluid flow through it. Seabed MPP technology is compatible with gas lift and can solve this problem. Allowing fluid phases anywhere from 100% water to 100% gas, helico-axial MPPs are ideal for handling transient flow generated by gas separation in the flowline. Although the reliability of seabed-based MPPs is well established, the ability to intervene and replace failed pumping systems with an A-frame workboat greatly increases a project's economics.

Seabed MPP technology is also compatible with ESP use. Using ESPs in the subsea environment can present difficulties, as with gas lift, imposing additional demands on the ESP and thus detrimentally affecting its operating life. Longer systems and larger diameters, higher thrust loads, and greater voltage and current requirements can all serve to shorten ESP run life. The relationship between increased ESP motor size and reduced run life has been proven. Seabed multiphase boosting is a tool that the production engineer can use to greatly reduce ESP size in situations that historically have demanded larger sizes, such as ultradeepwater environments, long tie-backs and their inherent flow implications, as well as heavy oil and flow assurance considerations at seabed conditions.

Incorporating seabed MPPs with downhole dual ESP systems into an integrated subsea design provides several advantages to the production engineer. The technology combination serves to decrease the size and thus intervention cost for the ESP system. Operating costs are reduced as the MMP can be changed out with a light vessel and remotely operated running tool. Uninterrupted production is secured because the MPP or ESP can continue to operate and produce fluid when one of the two systems is down. Flow assurance is improved as the seabed MMP imparts both heat and pressure to the fluid before it starts its journey down the long flowline. At the manifold, the MMP provides pressure balancing of fluids produced from several wells, which in turn controls commingled fluid effects like water hammering on the ESP. The technology combination also increases surveillance and control parameters (additional nodal points monitored) to assist domain experts in troubleshooting and understanding fluid dynamics in the production system.

A case study of the technology combinations

To quantify the relative benefits of various wellbore lifting and subsea flow boosting options, the integrated system as a whole must be modeled using an appropriate simulation tool. In this example, PIPESIM is used to investigate six scenarios:

1. Natural flow,

2. Subsea MPP,

3. Gas lift,

4. Gas lift plus subsea MPP,

5. ESP, and

6. ESP plus subsea MPP.

The system consists of four directionally drilled wells manifolded at the drill center and produced through a horizontal subsea tieback to a host platform situated at a 7,000-ft (2,135-m)water depth (Figure 1). For simplicity, the tubing geometry, reservoir and properties are the same for all wells. The Orkiszewski and Beggs-Brill flow correlations are used to calculate the two-phase pressure loss for vertical and horizontal flow, respectively.

To evaluate alternatives of natural flow, a nodal analysis was performed for a combination of ESP-assisted flow and subsea multiphase boosting. Locating the nodal analysis point between the manifold and the subsea booster intake allows full wellstream production to be evaluated for the four producing wells. A REDA JN21000 model ESP with 142 stages was selected based on a design rate of 15,000 STB/d per well and a pump set at 13,500 ft (4,120 m)measured depth (MD). This rate represents the lower range of the JN21000 operating envelope as it is anticipated that higher rates can be achieved using a VSD in combination with subsea multiphase boosting.

The helico-axial pump model used in PIPESIM characterizes pump performance using three correlating parameters. The flow parameter (FQ) and the head parameter (FZ) characterize the size of the impellers and the number of stages, respectively, thus defining a specific pump. A speed parameter (FN) representing the percentage of maximum speed is then adjusted based on the desired differential pressure for a given rate (or vice-versa). In this case, a constant pressure differential of 1,000 psi is considered and the power requirement is calculated based on a combination of pump performance and the electric oil-cooled drive mechanism.

System deliverability with the inflow curves reflects the incremental production from the ESP and the outflow curves reflecting the incremental production from the subsea multiphase booster (Figure 2). As indicated by point A, the system is unable to produce by natural flow. A subsea multiphase booster by itself is able to support production at a rate of 37,000 STB/d as indicated by point B. Point C represents ESP lift with no subsea boosting, resulting in a production rate of 62,500 STB/d, whereas point D considers a combination of ESP and subsea MPP, achieving a rate of about 72,000 STB/d.

The deepest possible injection point was selected for the gas lift design case. Because of the head associated with a 7,000 ft riser, the maximum tubing injection depth for conventional valves is about 4,000 ft (1,220 m) below the mudline. However, use of subsea high pressure valves rated for operating pressures of 5,000 psi permits injection at depths up to 11,500 ft (3,150 m) MD. Gas lift performance plots were constructed for cases with and without supplemental boosting by the subsea MPP (Figure 3). A gas injection rate of 6 MMcfd results in a liquids production rate of about 47,650 STB/d with the multiphase booster and 34,500 STB/d without it.

Comparing the alternatives, one can see system deliverability ranging from 34,500 STB/d (gas lift alone) to 72,000 STB/d (ESP with subsea MPP, Figure 4). Supplementing wellbore artificial lift with a subsea booster permits a 15% increase in production compared to ESP use alone and a 38% increase compared to just gas lift itself. However, subsea boosting in combination with gas lift requires more power since multiphase booster efficiency decreases with increasing gas volume fraction at the pump suction. Additionally, since the production system will not flow naturally, the subsea multiphase booster will allow production to be maintained in the event that wellbore lift methods experience downtime.

Management and surveillance

The design, execution and management of flow-boosting solutions require expertise in downhole pumping, seafloor multiphase boosting and subsea flow metering. In addition, experience with the specific hardware's correct operation and possible failure modes is essential to maximize run life. This is particularly important for ESPs. Data acquisition and management technologies are required to monitor and control all aspects of the resulting system. The combination of data and the expertise to use it can reduce lifting costs or extend ESP run life by years.

As subsea and downhole devices become more intelligent and provide more data and levels of diagnostics and control, a communications link is required, which allows large amounts of data to pass through to the surface in real time. Making these links communicate directly with their associated topside equipment over a high-speed data link without having to go through various intermediary devices will allow the subsea and wellbore devices to be used to their full functionality, improving reservoir management as well as fault-finding and diagnosis to prevent failures.

The subsea monitoring and control (SMC) platform is a new subsea surveillance system from Schlumberger Production Assurance Services. It serves as the central connectivity hub to downhole and subsea instrumentation for monitoring and controlling subsea processes (Figure 5). The system complements the production control system (PCS), an integral part of a subsea tree. SMC's primary role is to enable the applications of networking and monitoring and control in the subsea domain without interfering with the safety-critical functions of the PCS. Its platform is capable of communicating via hard wire or fiber optics at rates up to 100 megabits/sec. Instrumentation from all suppliers can be seamlessly connected to the platform, which can be implemented in the design phase through the use of open architecture and nonproprietary standardized interfaces.

Anytime cooperative lift technologies are used, there are operational challenges. Issues such as start-up, shut-down and as changing reservoir and/or operating conditions that affect one artificial lift system will undoubtedly affect the other. The SMC provides a vehicle to simultaneously monitor, control and optimize the performance of the inwell artificial lift and the seabed multiphase pumping systems. The SMC platform also allows the essential diagnosis of productivity issues related to the two systems. Using real-time data from subsea multiphase flow meters, sand detectors or even pump vibration measurements, system operation can be characterized with a high degree of accuracy. This results in the ability to make diagnostic decisions based on factual information in both the preventative and operational efficiency domains.

Summary and outlook

Recent technological advances in subsea well artificial lift and seabed flow boosting coupled with fast subsea diagnostics and monitoring systems are providing the flexibility needed to overcome subsea productivity constraints. With total system engineering and strong project management, synergies are created between subsea well lifting and seabed flow boosting systems. Flexible monitoring and control capabilities and implementation are needed to help avoid catastrophic failure before their occurrences. Prior knowledge of the dynamic events leading to failures is important to reducing intervention and downtime and thus increasing productivity as efficiency and performance improve over the life of the field, and can even make a previously non-producible field a very economical undertaking.

Acknowledgement

This article is a condensed version of "Flow Boosting Key to Subsea Well Productivity," Randall Shepler, Thomas White, Amin Amin and Mack Shippen, presented at the Deepwater Offshore Technology Conference, New Orleans, LA, USA, Nov. 30 to Dec, 2, 2004, which includes the complete list of references.