Enhanced recovery

Key Learnings From First 2 Years of a Full-Field CSS Development in Oman

The A East Haradh formation contains a 200-m-thick oil column of highly viscous oil, with viscosity ranging from 200 to 400,000 cp.

jpt-2017-03-techsyn179833cssdevelopoman.jpg
Saudi Aramco

The A East Haradh formation contains a 200-m-thick oil column of highly viscous oil, with viscosity ranging from 200 to 400,000 cp. Because of the high viscosity, first production was considered possible only by the use of thermal enhanced-oil-recovery techniques, starting with cyclic steam stimulation (CSS). This paper presents key learnings derived during this initial-operations phase of CSS in the A East Field, including key trial results on different well completions and artificial-lift systems.

Overview of Field Startup

In light of the results of a new geochemical characterization study of the crude extracted from a core, cold production was deemed feasible in the crestal area of the field. Viscosities at the top of the Haradh were estimated at 200 cp, lower than previously thought, and progressing cavity pumps (PCPs) were installed in 32 wells to start a cold-production phase.

Cold production started in March 2013 and lasted until the end of 2014, when all wells in the field were converted to CSS. The cold-production period allowed early depletion of the reservoir and later improvement in steam injection. A pressure drop of up to 20 bar was observed, and fluid-level measurement in the wells and PCP performance suggested good pressure communication between the wells.

Despite some early challenges, first CSS production was promising and, within a few months, was ramped up to 70% of the targeted CSS field peak oil rates.

Overview of CSS Performance

A typical CSS cycle in an A East well is shown in Fig. 1, using the wellhead temperature sensor as an indicator. The cycle starts with the injection phase for several weeks (initially 4 to 6). After that, the well is closed for a soaking period of a few days and then opened for free flow, which lasts for up to 3 weeks. The well is intervened with a flush-by unit (FBU) to prepare for production, followed by starting the beam pump. At the end of the production cycle, the well is stopped on the basis of end-of-cycle criteria and intervened again to prepare the well for steam injection for the subsequent cycle. The overall cycle duration is typically between 100 and 300 days and is dependent on the performance of the well with respect to preset operating envelopes.

jpt-2017-03-keylearningfig1.jpg
Fig. 1—Typical CSS cycle phases in an A East well.

 

Wellhead temperature in the production phase starts high in the beginning of the CSS cycle and then declines with time. From actual valid well-test data, there is a clear declining trend of the liquid and oil rates associated with and linked to the drop of the wellhead temperature. This is mainly because of the cooling effect after back producing the injected fluid. Hence, the pump efficiency deteriorates at lower temperatures because of the high oil viscosity, and this is observed in the reduction of liquid/oil with time in the production-test data.

Operating the CSS in A East Field

Artificial Lift Challenges and Mitigations. The initial plan for A East Field was for development with steam bypass pumps (SBPPs). However, design constraints led the team to operate the wells as dedicated steaming through tubing without the use of the SBPPs, followed by reinstalling rods and pumps for the production phase. The new approach increased the demand for resources. The selected artificial lift covers a reasonable production range but has some limitations, especially in the high-viscosity range.

SBPP—Management of Change and Effect on CSS Operation. In the initial plan, all CSS operations were planned to use the SBPP. Because of the significant depth of the reservoir and the need for minimal steam-quality loss downhole, the proposed efficient approach using the SBPP was changed. The change involved using vacuum-insulated tubing (VIT), which provided better steam-quality preservation. The thermal expansion of the VIT did not match the rod strings, and the added length needed to pull out the rods at surface made the SBPP less favorable for this application.

An alternative plan was implemented to make use of the VIT benefits and operate CSS with dedicated injection- and production-mode completions. The early conversion took significant time. All operating procedures for hoist and FBU had to be adjusted for the changes of operation, including a new standardized killing procedure.

Beam-Pump Operating Envelope for Highly Viscous Oil. Beam pumps in A East Field can operate with oil viscosity up to 5,000 cp. This limitation becomes an issue during two periods of the cycle—pump startup after conversion when the well is killed and end of production in a cycle.

Start of production was challenging for some wells, and a typical dyno card confirms the pump’s inability to close both standing and traveling, likely related to viscosity.

To mitigate the challenges of starting up the pumps, the following methodologies were tested:

  • Solvent injection (light-crude injection)
  • Hot-water circulation in the annulus
  • Prolonged shut-in time after killing the wells, to allow the hot fluids from the near-wellbore region to warm the well
  • Slow startup of the wells

The most reliable method was starting at very low speeds for 24 hours. Although the low speeds are not recommended because of gearbox-lubrication concerns, it is set for a maximum of 24 hours until the fluid temperatures rise and viscosity decreases for improved fill­age and pump performance. For wells that were extremely difficult to start even at lower speeds, annulus steam injection at low temperature and pressure was deemed effective (approximately 200°C and 3000 kPa).
The end of the production cycle also presented a challenge as the well cools down and viscosity increases. This viscosity increase affected pump performance. A review on artificial-lift selection for future development is planned, to address the current limitations.

Well- and Reservoir-Management Challenges of CSS Operations

CSS operations require a high level of planning and managing of interfaces. In the A East Field, the wells are fully converted. The full production completion is pulled out, stored, and reinstalled later after steam injection has occurred. To maximize the efficiency of a CSS cycle, the full process was mapped, the interfaces between teams were defined, and roles and responsibilities were assigned. That included the redefinition of custodianship for the material by the well-­intervention units and the reinforcement of tracking pump tear down and reports. The change had to be made to accommodate the operational shift from SBPP to dedicated modes.

Some challenges were experienced during surveillance activities. The activities were affected by the high column of viscous fluids in the well, made worse by the well-killing procedure. This problem was mitigated by changing the intervention times to be approximately 3 days after the injection-termination date. This allowed for logging while the well was hot and at much lower viscosity and for standardizing the acquisition of the logs for time-lapse analysis.

Optimization: Future of CSS in A East

Optimization in a CSS field is extremely challenging because it requires the integration of different parameters and is highly dependent on where the well is in the cycle. The team successfully managed more than 700 optimization changes in A East in 2015, requiring significant analysis time and decision making in a dynamic system.

In order to minimize the time spent on optimization and reduce reaction times, all wells in the A East Field were equipped with variable-speed drives. The wells can self-optimize. In addition, there is an ongoing trial in four wells known as the Beam Lift Automated Delivery Evolution (BLADE) project. The programmable logic looks at the preset dead band variable and increases or decreases strokes per minute, depending on changing conditions. The typical duration to review and execute an optimization request is approximately 1 week; however, the BLADE well can achieve the change in minutes. Implementation of the BLADE project is anticipated on all the wells in A East in 2016. The project team is looking into linking the optimization signal to the well-test fieldware, to ensure the capture of the optimized volumes.

Conclusions

The CSS development in A East Field has been in operation for almost 2 years, and significant learning has been achieved and modifications have been taken on board to optimize ongoing performance. A number of challenges are still being faced, but, within this short period of time, the team has achieved a steep production increase and has streamlined the overall CSS well-conversion process to maximize the efficiency of the CSS planning and operations. New technologies are supporting the management of the wells and the integration of production data with new geological and structural insights from the latest seismic interpretation. Taken together, these efforts are paving the way to continued success and providing the confidence to mature plans for further field expansion.

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 179833, “Key Learnings From First 2 Years of a Full-Field CSS Development in Oman,” by Solenn Bettembourg, Steve Holyoak, Abdullah Alwazeer, Mohammed Manhali, Mohammed Rawahi, and Amur Habsi, Petroleum Development Oman, prepared for the 2016 SPE EOR Conference at Oil and Gas West Asia, Muscat, Oman, 21–23 March. The paper has not been peer reviewed.