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.
Qiu, Yue (Missouri University of Science and Technology) | Wei, Mingzhen (Missouri University of Science and Technology) | Geng, Jiaming (Missouri University of Science and Technology) | Wu, Fengxiang (Daqing Xinwantong Chemical Co. Ltd.)
This paper presents the detailed descriptions of successful field application for a high-temperature and high-salinity resistance microgel in a mature reservoir in the northwest part of China. The reservoir with low permeability (230 md) experienced serious vertical and lateral heterogeneity problems, which caused low sweep efficiency and high water-cut (more than 95%). The treatment was designed based on laboratory experiments and experience from previous field application, providing detailed information of mechanism of microgel treatment and project execution. Thermal stability test showed that the microgel could resist the salt concentration up to 230,000 ppm at 125 °C for more than 1 year. From the core analysis, permeability of the long-term water-flooded zone was measured around 1,489 md, proving the evidence that high-permeability zones existed. Pilot test has been done before field application and valuable experience about how to design the injection parameters was provided. According to the information from laboratory experiments and the pilot test, four injection wells associated with nine offset production wells were selected for microgel treatment. For about 10 months treatment, 169 t of microgel was injected by five slugs.
Gradually increased injection pressure suggested that microgel could be placed deeply into the reservoir. The ultimate incremental oil production was approximately 29,635.8 t with the water cut decreasing from 95.3% to 93.1%. Microgel can be successfully used in relative low permeability (230 md) reservoir with harsh conditions for conformance control.
Ampomah, W. (Petroleum Recovery Research Center) | Balch, R. S. (Petroleum Recovery Research Center) | Grigg, R. B. (Petroleum Recovery Research Center) | Will, R. (Schlumberger Carbon Services) | Dai, Z. (Los Alamos National Laboratory) | White, M. D. (Pacific Northwest National Laboratory)
The Pennsylvanian–age Morrow sandstone within the Farnsworth field unit of the Anadarko basin presents an opportunity for CO2 enhanced oil recovery (EOR) and sequestration (CCUS). At Farnsworth, Chaparral Energy's EOR project injects anthropogenic CO2 from nearby fertilizer and ethanol plants into the Morrow Formation. Field development initiated in 1955 and CO 2injection started December 2010. The Southwest Regional Partnership on Carbon Sequestration (SWP) is using this project to monitor CO2 injection and movement in the field to determine CO2 storage potential in CO2-EOR projects.
This paper presents a field scale compositional reservoir flow modeling study in the Farnsworth Unit. The performance history of the CO2 flood and production strategies have been investigated for optimizing oil and CO2 storage. A high resolution geocellular model constructed based on the field geophysical, geological and engineering data acquired from the unit. An initial history match of primary and secondary recovery was conducted to set a basis for CO2 flood study. The performance of the current CO 2miscible flood patterns were subsequently calibrated to the history data. Several prediction models were constructed including water alternating gas (WAG), and infill drilling using the current active and newly proposed flood patterns.
A consistent WAG showed a highly probable way of ensuring maximum oil production and storage of CO2 within the Morrow formation.
The production response to the CO2 flooding is very impressive with a high percentage of oil production attributed to CO2 injection. Oil production increasingly exceeded the original project performance anticipated. More importantly, a large volume of injected CO2 has been sequestered within the Morrow Formation.
The reservoir modeling study provides valuable insights for optimizing oil production and CO2 storage within the Farnsworth Unit. The results will serve as a benchmark for future CO2–EOR or CCUS projects in the Anadarko basin or geologically similar basins throughout the world.