This paper reviews the fluid contact analysis of the Marmul Gharif South Rim (MM GSR) heavy oil field in the South of the Sultanate of Oman. The field is highly compartmentalized by several faults into 17 blocks in total with a large variation in well density within those blocks. The reservoir in this field is the shaly-sand Gharif formation, in which the Middle and Lower Gharif are separated from each other by either a paleosol or competent shale. The hydrocarbon in these sands has an observed viscosity variation as a function of height above free water level (HAFWL) due to biodegradation. This variable viscosity has been observed in a large number of oil samples with higher viscosity close to the oil-water contact (OWC). The sands tend to be vertically discontinuous in the wells, so that direct observation of the OWC on logs is very rare, causing most well logs to yield only water up to (WUT) or oil down to (ODT). Accurate pressure gradients are difficult to obtain due to the low density contrast of heavy oil against the fresh formation water. Consequently, the OWC is not readily identified in certain blocks. This has resulted in either over-estimating oil volumes when substituting WUT or under-estimating volumes when substituting ODT in specific blocks of the field. In addition these cases also result in a lack of reliable constraints for estimating high and low case oil contacts. Methods, Procedures, Process A viscosity based approach was used to overcome gaps in the fluid contacts data-set and provide essential information for future field development. The approach utilizes the viscosity data in each block to determine representative base case contact along with shallow and deep cases. The results of this analysis were confirmed by production data and are consistant with the ODTs from horizontal wells. The resulting fluid contact is then used as an input to the saturation height function which is used later as an input to calculate in-place volumes. Results, Observations, Conclusions Viscosity based contact provides a more robust fluid contact definition in areas where traditional methods resulted in data gaps. The paper presents a detailed methodology of this approach. Novel/Additive Information The results of this work are an essential component of optimizing the understanding of the fluid contact in the field, which helps to develop the field efficiently by drilling the oil producers and water injectors in more optimum locations.

Optimising the late-life development of heavy oil reservoirs due to biodegradation in a fresh water aquifer remains a challenge in the industry. When the variation of viscosity with depth is coupled with a significant degree of compartmentalisation due to structural complexities, the identification of a technically and economically viable development requires an integrated approach in field development studies. This paper presents a case study for such a complex field, a Gharif reservoir situated in the Eastern Flank of the South Oman Salt Basin. The integration between various data sets from across disciplines of varying fidelity and by adopting a decision-based planning approach has achieved two outcomes. Firstly, the highest field production since coming on stream; and secondly, the delivery of an updated Field Development Plan (FDP) that unlocks remaining hydrocarbon potential in a phased approach to mitigate key risks. On stream since 1981, the heavily compartmentalized Marmul Gharif South Rim Field has evolved from a primary depletion to a mature waterflood by flank injection. The sands, distributed in a rim setting with a steep dip tend to be vertically discontinuous in the wells, so that direct observation of fluid contacts is very rare and most wells yield only a Water Up To (WUT) or Oil Down To (ODT). In addition, the poor contrast of heavy oil density against fresh formation water makes it difficult to obtain accurate pressure gradients. The field can be subdivided into a number of compartments with varying degrees of communication from complete hydraulic independence to weak/moderate pressure communication. Over the course of 2016-17, a study was carried out by a multi-disciplinary team to deliver a FDP. By integrating existing data, the team created a new structural framework. This involved integrating faults based on Bore Hole Images (BHI) together with seismic re-interpretation; analyzing production and pressure data for connectivity mapping; updating the OWC assessment which considered oil biodegradation as a function of height above free water level. This was followed by combining the new insights into a fit-for-purpose dynamic modelling approach which led to the identification of new infill/appraisal targets and formed the basis of the redevelopment plan. The increased understanding of the field has allowed early WRFM activities which contributed to increase production by the order of 20%. The effort has materialized into an improved field understanding and delivered a rejuvenation plan with an immediate impact of unlocking reserves with the drilling of 5 drilling & appraisal targets in 2017. This is followed by a phased development with 30 development and 3 appraisal wells in Phase 1; and additional 65 development and 1 appraisal well in Phase 2, to increase the field recovery factor by 5%.

In this paper, recent EOR field trials are discussed to demonstrate the value of in-well fiber optic (FO) applications. The trials are in a field in Oman that has been considered for an enhanced oil recovery (EOR) development. Polymer Flood and Steam Injection have been proposed as alternative EOR methods and both are being studied. A recent polymer injectivity test and steam trial were conducted in order to de-risk uncertainties in a full field development and this paper presents the application of FO in these EOR trials to help meet these objectives. The fiber optic approach is viewed as an alternative technology to production logging and it provides the option of real time acquisition. In one area of the field, a shut-in well was converted to a polymer injection well and utilized for a single well injection test (SWIT). The test was carried out for six months to quantify the inflow profiles and injectivity to the reservoir under matrix conditions. For the steam trial in another area of the field, three producers and one injector with FO were utilized to demonstrate the feasibility of a horizontal well steam development and to evaluate the requirement and effectiveness of injection conformance. FO analysis from both trials concluded that the Distributed Temperature Sensing (DTS) and Distributed Acoustic Sensing (DAS) combination can be successfully used for injection conformance profiling. DTS/DAS measurements were taken during the course of the polymer injection test. These indicated that conformance was incomplete from the onset and deteriorated during the course of the test, with a large proportion of fluids in-fluxing into the reservoir through a narrow section at the toe of the well. One of the main objectives from the steam trial was to measure and manage conformance along the horizontal steam injector. Use of FO helped demonstrate the importance of managing conformance in order to achieve satisfactory sweep efficiency. This paper explains how these new technologies play a key role in reducing the uncertainties in reservoir performance in EOR developments. The combination of FO (DTS and DAS) data sets allowed the interpretation of data gathered to complement each other and provide more comprehensive conclusions.

This paper will discuss the evidence gathered proving the presence of Nothing-Alternating-Polymer (NAP) mechanism, in a current Polymer flood pattern during injectors offline periods, and the extension project designed to test and control NAP in conjunction with a nearby pattern in a horizontal wells environment. This project will help unlock a pragmatic Fullfield development, and highlight the associated benefits from a project’s perspective, leading towards huge savings and flexible operating conditions. Practical considerations and suggested operational methodology is also discussed.

The Shuaiba formation is one of the key contributors to production across the Middle East region including the Sultanate of Oman. However, the play was thought to be largely “creamed” – where the best prospects have been exploited in the concession area of Petroleum Development Oman. The remaining potential in areas of low relief was thought to be limited, with concerns around small volumes and early water breakthrough. However, advances in seismic, drilling and logging technologies coupled with new geological and petrophysical interpretations have boosted the outlook of Shuaiba across North Oman. This has been strengthened by a realization of the role of facies to trap hydrocarbons. When low Hydrocarbon Saturations are observed, it is important to understand if a structure was not charged at all, or if low Hydrocarbon Saturation is an artifact of poor facies encountered. In the worst case, misinterpreting the role of facies may result in missing opportunities. This paper consists of several case studies of Lower Shuaiba reservoirs. Existing petrophysical and geological studies identified several facies in Lower Shuaiba, with rudist facies being the best in terms of reservoir properties (porosity, permeability, and hydrocarbon saturation). All facies have relatively constant porosity in the range of ~23-26 p.u., and almost 100% calcite composition. The comparison of observed Archie Saturation compared to saturation height function is commonly used for facies identification in discovered fields, where free water level and fluid properties are known. However, this approach doesn’t help during the exploration stage. Formation pressure data are usually scattered, but mobility profiling could be helpful. We found that the best facies are clearly visible from nuclear magnetic resonance (NMR) logs largest porosity bins. Sidewall core, formation pressure mobility profiling, and downhole sampling prove this observation. As a result, several fields were discovered despite showing low or missing pay in exploration pilot holes. Horizontal sidetracks geosteered through the best facies showed good commercial rates during well tests. This information supplements the general understanding of Lower Shuaiba in Northern Oman for fields where no core has been taken. This paper demonstrates how advanced technologies and integrated interpretation triggers new discoveries where basic wireline logs show ambiguous results. This success has brought the play back into focus with follow-up opportunities identified in different segments.