Tewari, R.D. (GNPOC) | Raub, M.R.B.A. (GNPOC) | Omar, M.I. (QP) | Fenghan, B. (GNPOC) | Moris, M. (GNPOC) | Jelani, J. (PRSS) | Ramachandran, S. (AWT) | Fooks, A.L. (AWT) | Peden, J.M. (AWT) | Montague, Eamonn T. (Brunei Shell Petr. Sdn. Bhd.)
This paper describes the importance of well construction & well integrity and its relationship to reservoir management. Productivity enhancement studies in combination with reservoir simulation modeling on the Greater Heglig fields have revealed that well performances and production related problems were largely related to poorly designed wells and poor cementing practices. As a result, water channeling and cross flow across wellbore dominated true well performance characteristics contributing to very high water cuts in the majority of the producers in Greater Heglig fields. Separating the mechanically induced well behaviour from reservoir behaviour helped history matching the wells greatly, findings of which were subsequently validated during the study through running of ultra sonic imaging tool. The ultra sonic logging campaign proved the existence of channels, micro annuli's and cross flow across the wellbore causing a "water channeling phenomena" of up to 90% water cut across majority of the wells. As part of the productivity enhancement program for the Greater Heglig fields, a total of 23 sidetrack candidates have now been identified to capture the remaining developed reserves of ca. 30.0 MMstb, which will otherwise remain unproducible from the existing wellbore's. In addition to this, fit for purpose sidetrack well designs and construction together with good cementing practices will be required to ensure well integrity to improve reservoir management of the Greater Heglig fields.
The RR2/RS2 reservoirs of Baronia field are in communication through a localized sand window in an otherwise thick and persistent shale bed which separates the overlying RR2 reservoirs from RS2 reservoirs. These twin layered reservoirs are operating under the influence of large initial gas cap (m>1.5) and a moderate down dip aquifer support. Gas Injection in the Gas Cap started in 1993 in line with the changed reservoir management philosophy as a result of drilling of horizontal producers in the flank areas to accelerate the production. Gas injection was initiated with an aim to maintain the reservoir pressure for sustained oil production and decelerate the aquifer encroachment thereby enabling the field to be produced without excessive water cut. The first full field 3D/3P simulation study using black oil simulator was planned in 1998-99 to review the performance history during last 25 years or so and to formulate the future development strategy. The study suggests substantial increase in recovery factor by 2020 AD by about 8 % over the initial estimated recovery factor of 31 %. The history match could be obtained by considering convex upward trend for wetting phase and substantial reduction in krg.
An element of uncertainty existed in the book value of OIIP. It has been observed in the past that the initial water saturations estimation based on mercury injection experiments were reportedly at odds with the log derived saturations. In general, log derived initial water saturations were found to be lower than those derived from air-mercury injection method. Contrary to the above observations, when the model was initialised under gravity-capillary equilibrium with initial water saturation based on J-function/capillary pressure data obtained from air-mercury capillary pressure experiments, the OIIP after initialization was found to be significantly higher than the book value. A modified f-Swc correlation had to be used to match the book value. Apprehending the possibility of an underestimated book value of OIIP to be one of the reasons for difficulty in matching well/Field GOR, a sensitivity simulation run was made with the original f-Swc correlation based on air-mercury capillary pressure experiments which had yielded higher OIIP. The history match was again attempted with the original (unmodified) rock curves. Our experiences during history matching revealed that despite substantial increase in OIIP, the need of convex upward trend for wetting phase was still required. However, unlike the previous case, the krg curve did not require any reduction from its original trend. The requirement of convex upward trend for wetting phase in both the cases may be attributed to inter as well as intra-layer variation of areal permeability in vertical direction at microlevel of heterogeneity and the depositional sequence whereby comparatively higher permeability RS2 reservoirs are overlain by lower permeability RR2 reservoirs. The oil accumulation in RR2/RS2 reservoirs is well demarcated by the presence of OGOC and OWOC with reasonable number of wells located in the vicinity of fluid contacts to justify original contacts. The results of the sensitivity studies, therefore, indicate the possibility of OIIP being underestimated by as much as 15-20 % and opens up the scope for reassessment of OIIP which may be as high as 320-330 MMSTB as against the book value of 274 MMSTB.