Debottlenecking Through Produced-Water Partial Processing Unlocks Production
An operator in the western Gulf of Thailand installed two water-management partial-processing systems on its mobile offshore production units (MOPUs) to increase oil production. Water removed at the production manifold is treated and transferred directly to the injection system, thus bypassing primary separation, transfer piping, fluid heating, and floating storage facilities. Water debottlenecking increased oil production by 80% and reduced the in-field transfer volume by 62%.
In mature oil basins, the ability to sustain oil production depends on managing an increasing volume of produced water. The partial-processing method seeks bulk (not complete) removal of a throughput-constraining phase from oil and gas production using compact processing equipment. Partial-processing technology normally is installed on facilities that have space or weight constraints, where traditional separation technologies will not fit. Fitting within or around existing process equipment, partial-processing equipment maximizes the capability of an existing facility footprint. The constraining phase may be gas or water, and specific technologies are available to address each. The application detailed in this paper addresses produced-water debottlenecking. Removal of the water constraint unlocks production potential from mature or marginal fields and has been shown to increase hydrocarbon production.
Design Stages and Setup
For water-constrained systems, the most significant benefit comes from the removal of bulk water as far upstream as possible. High-water-cut wells are combined into a discrete manifold that may handle part or all of the field production. The partial-processing system is on this manifold, upstream from the existing process equipment. Debottlenecking at this point opens capacity in the flow lines, transfer piping, and processing facilities. The partial-processing skid can be installed on unmanned platforms with limited utilities and space and weight constraints.
Bulk water removal and treatment may have two or three stages. The first stage, preseparation, involves bulk water removal from the multiphase-flow stream. A specially designed liquid/liquid hydrocyclone (preseparator) removes a bulk portion (60–95%) of the water from the flow stream.
Next, the removed bulk water passes to the deoiler hydrocyclone, which operates in a standard produced-water-treating mode. For example, the preseparator will reduce oil content from 10 to 0.2%. The deoiler will take the 2,000‑ppm oil down to or near discharge quality (20–50 ppm), depending on oil properties, pressure drop, and temperature.
A tertiary treatment stage is optional and is used for difficult separation (e.g., cold fluids with heavy oil) or very stringent disposal requirements (e.g., low oil-in-water levels for enhanced-oil-recovery injection). This stage uses a compact flotation unit (CFU) for both degassing and oil polishing. The CFU removes gas effervescing from solution after the deoiler (which can be 5–10% of the gas void fraction) and uses that gas to float the fine oil droplets.
A partial-processing system is installed on the unmanned wellhead platform to unload the bulk produced water that is constraining processing and production. A bypass valve is installed after the partial-processing offtake to push fluids to the system. The partial-processing system has a two-stage liquid-treating process. The first stage is a preseparating hydrocyclone to provide bulk oil/water separation. This is followed by a deoiler hydrocyclone to provide oil removal from the separated water. If required, solids are removed by a desander hydrocyclone. The preseparator reject stream is sent back into the production line (after the bypass valve), while the deoiler reject goes to the drains. Water is disposed, either overboard or through injection. The oil phase, with a lower water cut, continues to the flowline transfer to a centralized processing platform, where traditional separation and produced-water treatment occurs.
A mass-balance example shows a capacity increase for the production flowline. Using 50,000 B/D total production at 90% water cut shows that only 5,000 B/D of oil is being produced. A partial-processing system is installed to treat 40,000 B/D of water (89% of the total). This water is removed from the production line and treated for disposal. The new production rate is 10,000 B/D at 50% water cut. Eighty percent of the fluid volume is removed from the production line, which enables the existing facility to operate more efficiently and allows more oil to be added from new, cut-back, or shut-in wells.
Fig. 1 shows a schematic of the existing production and processing systems. The wells are electrical-submersible-pump (ESP) -driven and produce to the unmanned MOPU through a production manifold. Wellhead flowing pressure and temperature are 75–80 psig and 75°C, respectively. The two facilities considered produce approximately 40,000 and 60,000 B/D of liquids at approximately 90% water cut. Primary separation occurs in a two-phase gravity separator on the MOPU with gas going to the flare. The combined liquids (oil/water) are sent to a surge vessel before being heated and pumped to the floating storage and offloading vessel (FSO). The liquids are heated to greater than 60°C to prevent wax formation in the infield transfer line. Oil and water separation occurs on the FSO by gravity settling. The oil is stored for offloading, while the water is returned to the MOPU through a separate infield transfer line. Biocides and oxygen scavengers are added to the water before injection into the disposal well.
In early 2015, each MOPU process system was operating at full capacity. While fluids production had increased, oil production had decreased because of increasing water cut. An infield drilling campaign was planned to restore oil production and bring on new ESP wells; however, the facilities had no capacity for the additional production. The primary bottlenecks were two-phase separation on the MOPU and the infield transfer lines to and from the FSO.
The challenge was to increase total liquids production from approximately 100,000 B/D to greater than 180,000 B/D (at 90% water cut), which should yield an 80% increase in oil production (e.g., from 10,000 to 18,000 B/D).
A partial-processing-system solution that would meet the design criteria was proposed in early 2015. A two-stage liquid/liquid hydrocyclone system could meet the space and operability requirements while providing the desired water-separation and -treatment levels.
A successful field trial led to the design and integration of a full-scale system for each MOPU. Fig. 2 provides a flow schematic showing the retrofit location of the partial-processing system and other changes made to the MOPU for liquids processing. A dedicated two-stage hydrocyclone skid consisting of a preseparator and a deoiler was located to receive fluids directly from the production manifold. The target total liquid production on Platform D was 80,000 B/D, of which 55,000 B/D (69%) would be treated by the partial-processing system, with the corresponding flows on Platform E at 100,000 and 75,000 B/D (75%), respectively. The water-cut levels remained nearly constant on both MOPUs at 88–90%, and the partial-processing skid was designed to handle up to 85–96%.
Fluids from the manifold were directed to the partial-processing skid with bulk water removal (approximately 90%) occurring in the preseparator. The reject stream, containing approximately 90% oil plus any gas, was returned to the manifold downstream of the diversion valve to continue to existing facilities. The separated water is treated by the second-stage deoiler, with water going to a surge (degasser) drum and the reject stream going to drains. The manifold fluids (reduced from 90 to nearly 50% water cut) continued to the existing gravity separator.
A retrofit was made to allow for three-phase separation that provided additional water handling. The removed water was treated by a deoiler vessel that was converted from an existing desanding hydrocyclone vessel. Of the production water stream, 75% is removed and treated by the partial-processing skid, 10% is removed and treated by the production separator and retrofit deoiler, and the remaining 15% reports to the FSO. The final transferred liquid stream was maintained at a minimum 50% water cut to prevent flow-assurance issues when transferring to the FSO. All treated water is disposed by injection on the MOPU.
Skid System Design
Fabrication of the two full-size partial-processing skids was completed in 16 weeks. Both the preseparator and deoiler vessels are oriented vertically to meet space requirements and to handle free gas. Vertical orientation prevents free gas build-up in the inlet chamber (primarily an issue with the first-stage unit).
Each MOPU had an available footprint for the skid of 8.8×3.3 m. The installed skid had a final footprint of 5.0×2.5 m, thus fitting into less than 50% of the allotted area.
The primary goal of the water-management retrofit was to allow increased fluid handling, which increased oil production from 10,000 to 18,000 B/D, an 80% increase. The reduction in operating expenditure proved to be as valuable as the production increase, and the entire project realized a 3-month payback.
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 187109, “Partial Processing: Produced-Water Debottlenecking Unlocks Production on Offshore Thailand MOPU Platform,” by C.H. Rawlins, SPE, eProcess Technologies, prepared for the 2017 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 9–11 October. The paper has not been peer reviewed.