Challenges and Learning from Developing Deep High Pressure Sour Reservoirs in Southern Oman by EOR MGI

Abstract

The Sour Cluster is located in the south of the Sultanate of Oman. Since the first oil discovery in 1997, a successful exploration drilling campaign was carried out in the Cluster, resulting in the discovery of several carbonate stringer oil and gas reservoirs. Approximately half the gas volumes are contained in a gas condensate field. This field will be developed along with the other oil reservoirs in the cluster and will export gas to market as well as provide a source of make-up gas for the miscible gas injection operations.In phase 1 of the development (normal depletion), the wells were routed to the existing station-B via the Early Development Facility (EDF). These facilities consisted of a number of remote manifolds, a 70 km multiphase pipeline to station-B and a new oil and gas compression train at station-B. Whilst the field was depleted via station-B, design and construction of the new plant (phase 2) progressed.First production from phase 2 commenced 10 April, 2012, some 3.5 years after the target first oil date. Despite the delayed start, this first oil milestone is considered a commendable achievement given the significant challenges faced by the project team during the execution phase. Building a facility to handle the extreme mixture of high pressure, sour corrosive fluids and gas contained within the sour reservoirs is a technical step-out for PDO, let alone the oil industry in general.The establishment of the new Production Station (Station-H) now provides the infrastructure for long term development of the area and a number of follow-on projects which will make use of these facilities are either already in operation (Phase 3) or in execution(Integrated Phase 4). Learning from phase 2 has been taken onboard in the design of these follow-on projects and the area will deliver robust value to PDO / Oman for generations to come. This paper will outline some of the key challenges that were overcome by the design and project execution teams on the phase 2 project and how lessons learned were taken onboard to facilitate project delivery of the extended larger MGI development for follow-up phases and in similarly challenging projects in PDO.

Experimental Evaluations of Polymeric Solubility and Thickeners for Supercritical CO2 at High Temperatures for Enhanced Oil Recovery

“…It is believed that with the implementation of MGI, an estimated 47% of the original oil in place (OIIP) could be recovered . In fact, the MGI process is already being implemented in which the field’s AG mixture is the main gas source . The injection process has been carried out by reinjecting the AG mixture into the reservoir at high pressures (up to 55 MPa), and due to the high reservoir temperatures (up to 377 K), the gas becomes miscible with the oil.…”

“…7 In fact, the MGI process is already being implemented in which the field's AG mixture is the main gas source. 8 The injection process has been carried out by reinjecting the AG mixture into the reservoir at high pressures (up to 55 MPa), and due to the high reservoir temperatures (up to 377 K), the gas becomes miscible with the oil. However, even though the oil in Field A is light (42°API), the significant viscosity contrast between the injected gas (0.1−0.03) and oil (0.23 cP) leads to viscous fingering, early breakthrough, and high gas-to-oil ratio, which would compromise the macroscopic sweep efficiency of the field.…”

New Approach to Alternating Thickened–Unthickened Gas Flooding for Enhanced Oil Recovery

“…16,17 The field has a harsh reservoir environment with a formation brine salinity of 275,000 ppm TDS (total dissolved solids) and a reservoir temperature of 377 K with low in situ water saturation. 18,19 It has been shown that both foam and WAG flooding are not applicable in this field as means of mobility control. 16 Hence, with Field A, it is believed that AG mixture thickening may be the only viable approach to counteract unfavorable mobility conditions and improve sweep efficiency.…”

“…Unlike foam injection and water alternating gas (WAG) flooding, the application of gas thickeners is not dependent on the reservoir rock petrophysical properties and fluid saturations . Field A in southern Oman has suffered from early gas breakthrough due to the high mobility of the AG mixture injected as part of an MGI process. , The field has a harsh reservoir environment with a formation brine salinity of 275,000 ppm TDS (total dissolved solids) and a reservoir temperature of 377 K with low in situ water saturation. , It has been shown that both foam and WAG flooding are not applicable in this field as means of mobility control . Hence, with Field A, it is believed that AG mixture thickening may be the only viable approach to counteract unfavorable mobility conditions and improve sweep efficiency.…”

Experimental Study of Miscible Thickened Natural Gas Injection for Enhanced Oil Recovery

“…In the Middle East, many MGI projects are currently being undertaken in carbonate reservoirs in which the injected AG often contains acid gases. − Field A, located in the Harweel cluster in southern Oman, has been recognized as a viable MGI candidate. The MGI in this field has already commenced where the source of the injection gas is the field’s AG . The AG mixture is reinjected into the reservoir at high pressure (up to 55 MPa) where it becomes miscible with the oil during the displacement at the relatively high reservoir temperature of up to 377 K. The AG in Field A contains CH 4 enriched with light and heavy hydrocarbon fractions found in natural gas and a significant amount of carbon dioxide at 10–25 mol% .…”