Novel Gas-/Liquid-Coinjection EOR Process Enters the Permian

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 230250, “Novel Gas-/Liquid-Coinjection EOR Process Enters the Permian, ” by Stuart L. Scott, SPE, David Schechter, SPE, and Gordon Pospisil, SPE, EOR ETC, et al. The paper has not been peer-reviewed. _ This paper details a new enhanced oil recovery (EOR) method successfully piloted by several operators in the Bakken and recently implemented in the Midland play of the Permian Basin. This EOR method uses a patented coinjection process injecting both produced water and natural gas. Single-well tests have established a gas-utilization factor (GUF) in the 4 Mscf/BO range, which is excellent when compared with other EOR processes. Introduction Surfactant injection has generated recent interest with successful pilots and projects in the Permian and Eagle Ford. These surfactant treatments have been implemented as opportunistic well treatments rather than a continuous EOR process, but generally have been more economic. This paper discusses a new coinjection process that uses produced water and natural gas injected at low pressure by a modular surface unit. This process has been shown to be effective for huff ’n’ puff EOR but also is suitable for conventional EOR expansions, waterflood extensions, stranded gas fields, gas-sequestration projects, and, additionally, for frac defense and short-term gas injection to mitigate flaring. In fact, one pilot project specifically targeted low-pressure gas injection and successfully achieved injection of 3 MMscf/D over a 2-week period. This demonstrated that this same process also can address short-term facility upsets, allowing production to continue. Novel Coinjection Process The patented coinjection process consists of a surface module that creates rapidly alternating slugs of water and gas in the injection well. These stable slugs increase the hydrostatic head within the vertical well column to deliver high bottomhole pressures using relatively low surface pressure. Slug flow allows very high gas volume fractions to be delivered to the reservoir without the natural segregation of gas and liquid in the wellbore or annular flow path. Slugs created at the surface have been demonstrated to retain their structure while moving down the wellbore and into the lateral section of the well. The increasing pressures with depth act to stabilize the flow structures for downward flow just as decreasing pressure destabilizes flow structures for upward flow, such as during production. The novel gas/liquid coinjection process is referred to as rapid switched stacked slugs (RSSS). Using a combination of liquid slugs and gas bubbles creates a multiphase gradient in the vertical wellbore that reduces the surface injection pressure required to achieve a high bottomhole pressure for injection. Multiple slugs exist in the vertical wellbore throughout the injection cycle, providing water-alternating-gas on a very short time interval and through an automated process. Effectively, 20 or more slugs will exist in the vertical wellbore at any given time, with less liquid injected early in the cycle and more liquid injected later in the cycle to build higher pressures.