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Sand-Control Technology for Water Injectors Improves Well Performance

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In 2014, a research and development (R&D) project was initiated to increase the life expectancy of Gulf of Mexico (GOM) Miocene and Lower Tertiary water-injection (WI) wells, several of which had suffered a severe loss of injectivity within only a few years of completion. The solution was to find a way to prevent fine material from entering the completion while sustaining high injection rates, with no loss of injection pressure or requirement for additional horsepower. A new flow-control device (FCD) and completion system were developed along with intrinsic nonreturn valves (NRVs) that prevent any backflow or crossflow during shut‑ins.

Developing the Flow-Control Technology

Tubing-deployed injection valves and regulators have been available for many years. However, these cannot address the problem of annular flow. The most-damaging factor in solids production is likely crossflow, wherein differently pressured injection zones can flow between layers inside the tubing or casing annulus. Crossflow can be eliminated only by blocking the flow at the sandface. This solution also would mitigate the damaging effects of water hammer by blocking pressure waves from entering the lower completion. Check-valve components must fit within sand-control screens or be deployed across multiple zones of the injection tubing.

During the R&D phase of the project, researchers used extensive laboratory testing, flow-loop testing, and computational-fluid-dynamics modeling to develop a series of NRV prototypes. The technology was designed to handle a variety of well conditions, including erosion, plugging, temperature, and repeated checking cycles. All FCD components, including the NRV technology, are manufactured with high-alloy stainless steel and tungsten-carbide components to resist tortuous downhole conditions for up to 15 years. FCD prototypes and design iterations were tested over 18 months and a final design was qualified to withstand repetitive pressure-checking cycles reliably at 1,500 psi (and up to 10,000-psi static differential pressure).  

The laboratory testing conducted to finalize the project development stage is described in detail in the complete paper; it consisted of leak-rate, erosion, plugging, and screen-construction stages. One determination of this testing was that the placement of the screen over the FCD joint could cause erosive wear because of the placement of the screen ribs over the valves. An alternative rib wire was designed that could place the FCD between wires without compromising the strength of the screen.

With laboratory and workshop testing completed by early 2017, the focus of the project shifted to identifying and organizing a field trial for the new technology in a low-cost, low-risk environment.

Field Trial

A Permian saltwater disposal well (SWD) was selected to test the system under the challenging conditions associated with injection of untreated produced water. SWDs are common across west Texas and Oklahoma, disposing of up to 30,000 BWPD/well. The FCD system was built on heavy-walled 4½-in. base pipe with an array of 630 NRVs. The quantity of valves is a function of the expected injection rate. To minimize flow velocity, and hence erosional concerns, the flow is limited to 40 BWPD/valve. The SWD selected for the field trial was approved for up to 25,000 BWPD, which corresponded to approximately 630 individual valves mounted in a spiral array into the base pipe (Fig. 1). The size and positioning of the valves is critical so that they can be mounted flush with the pipe; thus, a direct wire-wrap screen can be manufactured over them without interference. However, the purpose of the field trial was to test the valves under the most-challenging well conditions possible, so the test assembly was built without a sand screen.

Fig. 1—FCD test assembly with NRVs installed.

 

The test well was completed with the new system installed permanently on 4½-in. production tubing below a hydraulically set production packer. The system is designed to be deployed as the sandface completion or inside an existing fracturing pack. However, it also can be used on the production string to isolate flows below the production packer.

The test assembly was positioned at the top of the injection zone, which was completed openhole with approximately 2,000 ft of sandstone pay. A preperforated 4½-in. liner was run below the production packer to total depth. With the tubing plugged below the test assembly and pressure gauges set to record both the tubing and annulus pressures, the test was conducted by pumping down the tubing.

This SWD was newly drilled, and the formation was normally pressured; no previous injection or water disposal had been performed in the area. The well had been left suspended with kill-weight brine, and no pressure was initially observed on the wellhead. After displacing the tubing volume to lighter brine, a steady flow of produced water and approximately 300 psi of wellhead pressure were observed. Wireline was rigged up to set the pressure gauges and tubing plug. With the tubing plugged, all flow was diverted through the test assembly and a step-rate injection test was performed up to 10 bbl/min.

Well Operations

In late 2017, the FCD equipment was supplied from facilities in Aberdeen. The NRVs were installed on two joints totaling 21.5 ft. The well was completed successfully on 1 January 2018. The completion tubing was used for the entire completion to accommodate higher injection rates. This completion design placed the FCD at the top of the open hole. The field-trial-procedure overview, and the job log, are described in the complete paper.

Data Analysis

The first paired set of injection tests was conducted through the FCD, while the last pair were through a sliding side door and bypassed the FCD. Each injection test was conducted as a step-rate test up to 10 bbl/min with a hard shut-in to initiate water hammer and allow a pressure differential to develop across the FCD. In between tests, surface pressure was bled off to determine if the FCD would check pressure and flow from the annulus. The pressure drop across the FCD joints in both tests while injecting aligned well with one another and had similar curve matches.

At the end of each of the step-rate tests through the FCD joints, an abrupt shutdown of the pumps was performed to replicate the water-hammer event that can occur in a WI shut-in. During the shut-in tests, the downhole gauges recorded a drop of tubing pressure while the annulus pressure remained constant, indicating that the test assembly was checking and holding pressure.

For the shut-in test, pressure was bled off at surface and a small amount of flowback occurred. A 235-psi underbalance was created and held flat for more than 5 minutes before pressure began to increase slowly on the tubing. This provided evidence that the FCD can stop the majority of backflow; however, as the well settles, a leak will eventually be created. This leak took nearly 10 minutes to equalize, indicating a low velocity that could carry solids into the wellbore. Upon closing the well at surface, the tubing and annulus pressure equalized over 9 minutes.

After completing the test by injecting through the FCD, the process was repeated through the open sliding side door. With fully open communication between the tubing and the annulus, both pressures match, indicating a flow that bounces between the formation and surface. The authors concluded that the FCD joints do attenuate water hammer.

On the basis of the shut-in and leakoff tests performed through the FCD test assembly, several observations were made:

  • During initial cycles, the tubing pressure drops more than the annulus pressure. This phenomenon indicates the point at which the FCD check valves engaged to block annular pressure from entering the tubing.
  • The amplitude of the initial cycles is 30–40 psi and quickly drops to 10–15 psi for subsequent cycles, indicating that the tubing and annular pressures were isolated by the check valves that dampened the pressure cycles.
  • There is an approximate 180° phase shift between tubing and annulus pressure cycles, indicating that the tubing and annular pressures were isolated from one another.

Conclusions

This screen technology promises to eliminate some of the causes of premature WI well failures. By blocking pressure transients at the sandface, sand problems can be prevented and the life expectancy of WI wells can be extended. The primary objective of the field trial was to prove that the new technology can work at downhole conditions, checking against flow from the annulus to the tubing. Even though conditions were not ideal (injection pressures were lower than expected), evidence of the technology’s check-valve functionality clearly was visible during shut-in tests.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 192840, “Field-Trial Results for New Sand-Control Technology for Water Injectors,” by Steven Fipke, SPE, Tendeka; J.E. Charles, SPE, Shell; and Annabel Green, Tendeka, prepared for the 2018 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 12–15 November. The paper has not been peer reviewed.

Sand-Control Technology for Water Injectors Improves Well Performance

01 October 2019

Volume: 71 | Issue: 10

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