Enhanced oil recovery (EOR) is a general application used in mature oil fields to generate additional reserve growth. Several types of EOR applications are implemented in the oil industry. One such application is the injection of gas into a reservoir as a gas displacement recovery (GDR) mechanism to induce additional reserve growth. A specific type of GDR application is the immiscible water-alternating-gas (IWAG) displacement process. In this application a slug of water is put into an injection well, followed by gas, which exists as a separate phase from the water and oil. Water and gas injection slugs are alternated until the designed amount of gas has been injected, or as field production dictates. Continuous water (case water) is typically injected after the IWAG process.
Herein, the state-of-art of IWAG EOR is described from an extensive literature review. First, the theories of the recovery mechanisms that cause IWAG to produce incremental oil are described. These mechanisms include viscosity reduction, 3-phase relative permeability, oil swelling, and oil film flow, all of which are a function of fluid and rock-fluid interactions. Next, salient laboratory studies are summarized, including micromodel and core floods. These studies test pore-level characteristics, displaying ranges of residual non-wetting phase saturations (hydrocarbons) down to 0.13 to 0.25 and incremental oil recovery ranging from 14% to 20% of OOIP. Some experiments isolate a specific recovery mechanism in order to determine its validity and contribution to recovery. Studies generally point to the conclusion that the gas type shows no discernable difference in recovery character.
The paper concludes with a synopsis of results from small-scale field trials and field-scale projects in both heavy and light oil. Both simulation modeling and field trials are summarized. Projects have been implemented with varying types of gases, WAG ratios, and gas slug sizes, resulting in incremental reserve growth being reported in the range of 2 to 9%. The fundamental immiscible recovery mechanisms in IWAG can produce lower cost and faster response EOR projects, with moderate recovery efficiency gains.
Skrettingland, K. (Statoil ASA) | Ulland, E. N. (Statoil ASA) | Ravndal, O. (Statoil ASA) | Tangen, M. (Statoil ASA) | Kristoffersen, J. B. (Statoil ASA) | Stenerud, V. R. (Statoil ASA) | Dalen, V. (Statoil ASA) | Standnes, D. C. (Statoil ASA) | Fevang, Ø. (Statoil ASA) | Mevik, K. M. (Knutsen Subsea Solutions) | McIntosh, N. (Knutsen Subsea Solutions) | Mebratu, A. (Halliburton) | Melien, I. (Halliburton) | Stavland, A. (Intl Research Inst of Stavanger)
Declining oil production and increasing water cut in mature fields highlight the need for improved conformance control. Here we report on a successful in-depth water diversion treatment using sodium silicate to increase oil recovery at the Snorre field, offshore Norway, utilizing a new operational concept of using a stimulation vessel as a platform for the large-scale injection into a subsea well. A custom modified 35,000 DWT shuttle tanker was employed for the field pilot. This paper describes the vessel preparations and the large-scale interwell silicate injection operation. The operational aspects of the large-scale interwell silicate injection include; identification of injection vessel requirements, major vessel modifications, chemical logistic, general logistics to site, major equipment set-up on vessel, subsea connection, mixing and pumping schedules, onsite QC, and real time monitoring. Experience from these operations and lessons learned are included in this paper.
After the injection of approximately 400,000 Sm3 (113,000 Sm3 preflush, followed by 240,000 Sm3 of sodium silicate gelant and 49,000 Sm3 of postflush fluid) at injection rates up to 4,000 Sm3/d, the injection from the vessel was stopped and the well was put on regular seawater injection. Following more than two years of regular production, transient pressure measurements, tracer testing and water cut data are presented from the ongoing comprehensive data acquisition program. These results demonstrate clearly the achieved in-depth flow diversion through a delayed breakthrough of injected tracers and lower water cut in the relevant production well.
Polymer transport and preparation can present a key challenge in chemical EOR project implementation.
Hydrolyzed polyacrylamide in emulsion form presents some advantages, including an easier transportation and a simplification of the injection process. The trade off is a lower active concentration (~30% - 50%), which increases the volumes to be transported, as well as the presence of oil and emulsifiers, which may have unintended effects in the reservoir.
In this article, we compare two industrial and commercially-available polymers, one in powder form from the gel process, and the other in an inverse emulsion, with similar viscosifying power.
Properties of both polymers are investigated through rheological and screen factor measurements, filterability tests on bulk solutions, shear thickening behavior and resistance to shear degradation in porous medium. The likely origin of the observed differences is discussed in light of the two polymerization methods (bulk vs. emulsion) that lead to differences in polydispersity. Mobility reduction and residual resistance factor measurements during propagation tests at low velocity give some insight on the propagation of the stabilized oil droplets coming from the injected emulsion. Finally, oil recovery efficiency is investigated through secondary polymer injections on sandpacks. No significant difference was observed between the polymers in term of oil recovery or pressure behavior.
These results are relevant to oil companies planning polymer or surfactant-polymer pilots and considering the tradeoffs between emulsion and powder polymers.
Many offshore heavy oil reservoirs underlain by large aquifer are developed through cold production method: horizontal wells, with water coning/cresting being a major concern. Inflow Control Devices (ICDs) are often used to delay the water breakthrough by balancing the well inflow along the well section. However, ICDs have difficulties to mitigate the water coning/cresting after water breakthrough, leading to water bypass oil, premature well abandonment and low oil recovery. In this study, we propose the use of a dual completion technology, Bilateral Water Sink (BWS), assisted with ICDs to mitigate water coning/cresting in high water cut wells, therefore improving oil recovery for offshore heavy oil underlain by large aquifer.
To investigate the reservoir performance under this new production technique, a series of experiments were conducted in a scaled Hele-Shaw model, similar to a cross-section of horizontal wells. Identical flow behavior at each cross-section perpendicular to the well axis were assumed. The experiments resemble to the situation in which the ICDs have been successfully implemented to provide a uniform flow along the entire well section. The oil recovery, water cut and reservoir pressure were measured in each runs to quantify the effects of BWS wells on water coning/cresting mitigation and improving oil recovery.
The experimental results show that while ICDs mitigate the non-uniform production profile along the horizontal well section, BWS wells mitigate the water coning/cresting by dynamically modifying the pressure distribution in the reservoir. Experimental results also verify that the previously derived theoretical rates in BWS can efficiently suppress the water coning/cresting after water breakthrough. The quantitative and qualitative results demonstrate that BWS could reduce the water cut from over 95% in high water cut horizontal wells to less than 40 % and improve the heavy oil recovery about 4-6 times compared with that of conventional horizontal wells.
Those findings provide a new insight into offshore heavy oil production mechanism. Because of BWS's ability of converting an original bottom water drive system to a more effective edge water drive system, low water cut and high oil recovery can be achieved by utilizing the reservoir energy without using of heat.