The first triple-zone intelligent completions installed off the US West Coast are up and running in three of Plains Exploration & Production's (PXP) Rocky Point wells. PXP chose this approach to reduce the need for intervention as the wells water out over time. Further, the real-time pressure and temperature information being gathered has allowed stimulation treatments to be optimized as they are conducted.

Before selecting the intelligent completions solution, PXP and Schlumberger together carefully studied the expected total well life cycle and related economics for the wells. The full project management approach delivered the best completions solution from an engineering, procurement, installation and commissioning (EPIC) perspective.

While intelligent and advanced completions are a viable solution for completing most subsea or marine extended reach wells when intervention is not feasible, undertaking a full project management approach has proven to enhance long-term results.

The development plan for Rocky Point field includes drilling up to eight extended reach wells from the Hidalgo and Hermosa platforms, located to the east in Block 451 and to the south in Block 316, respectively. The lateral reach of these wells would range from 15,000 ft to 25,000 ft (4,575 m to 7,625 m). The final well count will depend upon each well's results and economic considerations.

Engineered completions study

In May 2003, prior to beginning the drilling project, an initial front-end engineering and design (FEED) study was performed to evaluate completion systems options. A cooperative relationship between PXP and Schlumberger enabled the clear definition of project objectives. The FEED study focused on these challenges:

• Evaluating zonal productivity for future development;

• Providing an easy-to-install and operate, reliable completion that allows for zonal isolation;

• Maximizing early, commingled production while minimizing early water breakthrough through selective zonal control;

• Maximizing completion longevity (reliability) to minimize total life-of-well costs;

• Eliminating or minimizing intervention costs;

• Minimizing the topsides footprint;

• Managing hydrogen sulfide; and

• Minimizing risks related to completion technology.

The long-term objective of any petroleum development must be good or better net present value (NPV) performance as compared to other investment opportunities. In this instance, the NPV could be seriously impacted by workover costs given a poorly designed or unreliable completion. Flow assurance remained a project priority from conceptual engineering through installation and workover.

The FEED study provided a design basis for the engineering and procurement work associated with installing extended reach drilling (ERD) intelligent completions in wells drilled from the Hidalgo and Hermosa platforms. The optimal completion scenario finally adopted provides for commingling fluid flow from four zones through remotely operated downhole flow control devices in the completion string. These devices will allow each zone to be isolated, without the need for coiled tubing intervention, as the OWC rises and renders it uneconomic. In return, this completion approach will save time and money, and have the potential to eliminate many of the risks associated with intervention.

Study specifics

The study began by defining all feasible completion options and then qualitatively prioritizing them based on the ability of each to meet the project's challenges. Once the potential options were defined, a Nodal model was built to measure the impact of data uncertainty and generate a series of production profiles that agreed on the impact of uncertainty mitigation. Decision and risk analysis (DRA) models were completed to quantify in real terms the potential project costs under success and failure scenarios, and the cost impact measured against the upside. Finally, completion options were evaluated.

Given study results, Schlumberger recommended that the best completion for the Rocky Point wells drilled from the Hidalgo platform would include hydraulically controlled valves, a dedicated downhole monitoring system and a chemical injection system for emulsion inhibition. This intelligent completion would tend to minimize intervention while maintaining the ability to control water production and maximize hydrocarbon production from each of up to four zones per well. All four zones in each of the three initial wells were perforated at once. By monitoring well performance, PXP has the option to selectively choke back and control the productive zones, while maintaining optimal downhole pressures and temperatures. These factors positively impact the field's financial performance.

Installed completions

Four zones were completed in each of three Hidalgo wells with three isolation packers. As the lower zone holds both the highest productivity potential and highest probability of water production, it was isolated with the lower isolation packer in the 7-in. liner. A custom-designed, multiposition, hydraulic, variable valve was used to control water production and reduce coning, increasing reservoir sweep. This valve was sized to allow for the maximum production rates.

The middle zones were commingled below a 7-in. isolation packer, and upper zones were commingled below the 7-in. production packer. Each of these zones is producing through an open/close hydraulic valve.

Chemical injection for emulsion inhibition occurs through a 3⁄8-in. hydraulic control line close to the top of the production packer. It also can be used to inject scale inhibitor, if needed.

The wells are cased with 95⁄8-in., 43.5-lb casing to an average depth of 18,000 ft (5,490 m) measured depth. The 7-in. liner is hung off of a hydraulic set liner hanger. A tapered 41⁄2-in. to 31⁄2-in. production tubing string was run to maintain completion strength while allowing for optimal gas lift efficiency.

High shot density (5 spf) perforating was used to ensure coverage in the highly laminated formations. The well was perforated by tubing-conveyed perforating in a single trip, and then killed prior to pulling the perforation string.

The monitoring system includes a single pressure/temperature gauge in the interval below each packer. A total of three gauges are connected using a single gauge line. These gauges can be used for:

• Reservoir pressure monitoring;

• Wellbore lift optimization;

• Productivity measurement and back allocation;

• Monitoring and variable control of the lower zone to reduce/delay water production;

• Individual zone transient testing while minimizing wellbore storage effects; and

• Vertical interference testing.

As each well was completed, stimulation was limited to acid treatments bullheaded from the surface through the tubulars.

The flow path from each zone is through a dedicated hydraulic, tubing-retrievable control valve into common 31⁄2-in. tubing. Commingled flow moves through the top multiport production packer into the 41⁄2-in. tubing to surface.

Communication with the control valve is maintained through a single dedicated control line. The multiposition, variable valve can be positioned anywhere between fully open and fully closed to control flow from the lower zone. Choking will be used to control the flowing bottomhole pressure at the sandface of zones producing water, thus limiting the drawdown at the sandface and delaying water production. This will increase oil production from the zones not yet producing water.

This valve was sized according to the initial reservoir model to suit emerging reservoir conditions. Its performance is being optimized to PXP's production and reservoir management objectives by modeling the ongoing data provided by the wells' instrumentation. These data include inlet pressure, tubing hydrostatic pressure, flowing bottomhole pressure, static reservoir pressure, downhole temperature, zonal flow rate and fluid characterization.

The open/close hydraulic, tubing-retrievable control valves for both the upper and middle zones enable two positions - fully open or fully closed - for water control.

A chemical injection mandrel, 41⁄2-in. gas lift mandrel with 11⁄2-in. injection valves and a tubing-retrievable safety valve are installed above the top packer.

Using the real-time data

Downhole pressure and temperature data are transmitted in real-time to PXP's district office. This enables the production and reservoir department to make quick, well-informed decisions as well operations (e.g., testing, stimulation and production) proceed.

With the intelligent completion equipment that is available today in the three Hidalgo platform wells, PXP is able to:

• Monitor reservoir behavior while stimulating individual zones;

• Use real-time pressure and temperature data from each of the producing zones;

• Reduce reservoir uncertainties related to sealing faults;

• Confirm the extent of the pressure support available from the aquifer;

• Evaluate the vertical conductivity between fractures in producing zones;

• Understand the water breakthrough behavior;

• Mechanically control water production; and

• Optimize production results from gas lift.

Ongoing services for the unit include a monthly reservoir and production evaluation based on the pressure, temperature and rate data gathered. In addition, a valve actuation service is in place to optimize valve efficiencies, as required. Additional Rocky Point wells are scheduled to commence from the Hermosa Platform during the fourth quarter of 2005.

A project management approach

PXP has taken a long-term, life-of-the-field perspective in developing and managing its Rocky Point asset, as illustrated by the design, build, manufacture, test, install and commission cycle of the advance intelligent completion systems in place today. Schlumberger was actively involved early on in the development planning process, helping to design a reservoir- and completion-driven business case. A clearly defined project scope, successful planning and skilled execution have resulted in a project that is meeting PXP's business objectives.