|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Original hydrocarbon in-place and aquifer influx for a reservoir can be estimated using the classical Material Balance Equation (F = N*Et + We). Being a single equation with many unknowns, this makes the solution to the equation non-unique with a wide range of OHCIP estimates. Including fluid contact tracking helps to constrain the range of OHCIP and better define the initial conditions of the reservoir.
The objective of the material balance study was to estimate the STOOIP and initial reservoir fluid contacts for two waterflooded reservoirs. The volumetric estimates of STOOIP for the proved area (defined by the HKO and ODT) gave very optimistic recovery factors to date. This paper will discuss the methodology used for estimating the initial reservoir condition by using fluid contacts tracking to constrain the material balance equation for production history match.
Reservoir A2 was discovered with no initial fluid contacts seen in the reservoir prior to the onset of production. Water injection started in the reservoir after fourteen years of production. Oil RF to date from the reservoir is over 61% of the volumetric STOOIP estimate (265 MMSTBO) using the first fluid contacts seen in the reservoir post-production.
Reservoir A3 was discovered with an OOWC and HKO with volumetric STOOIP estimate of 295 MMSTBO. Initial water injection started in the reservoir after fourteen years of production. Oil RF to date from the reservoir is 71%.
Integrating fluid contacts tracking in the material balance study helped constrain the STOOIP estimates and give more realistic values (45 – 50% for reservoir A2 and 60 – 65% for A3). The STOOIP and initial contact estimates from this study were used as basis for comparison with the dynamic simulation study and the results were within 5%. These case studies show that applying fluid contact matching in material balance can help with better estimates of STOOIP and initial reservoir fluid contacts.
This is of great importance to the optimum development of these reservoirs and has led to the identification of new drill opportunities in each reservoir.
The objective of this paper is to share learnings from the Okan field, highlighting successful strategies adopted to mitigate reservoir and operational decline almost 8 years without producer drilling or major rig workovers. Value gained is quantified to show that over a third of the current Okan production is tied to strategies adopted during the period of interest.
Details of the different wellwork methodologies are provided to communicate how value was maximized using minimal cost. Key strategies adopted that have created the Okan success story over the period of interest include the jacket-centric rigless wellwork approach which has resulted in a drop in overall wellwork costs as multiple wells on the same jacket are worked over in one mobilization. The use of interwell gas lift systems for isolated jackets unlocked reserves that would otherwise be uneconomic because of costly pipelay. In addition to enhancing production from wells requiring gas lift, the conversion of idle oil line conversions to gas supply lines for gas lift ensured available facility assets are utilized, bringing pipelay savings as well as production gain. Also, taking full advantage of the Okan Gas Gathering and Compression Platform, production from reservoirs with high GOR has been optimized, resulting in oil and gas gain without routine gas flaring. Challenges encountered and lessons learned are also shared in this paper.
As a result of the strategies shared in this paper, the current Okan production is over 30% higher than what it would have been without the deployment of these strategies highlighted. The same strategies can be transferred to other assets to obtain optimum value in these times of low commodity prices.
Ogbuagu, Frank (Chevron Nigeria Limited) | Afolayan, Femi (Chevron Nigeria Limited) | Esan, Femi (Chevron Nigeria Limited) | Obot, Nsitie (Chevron Nigeria Limited) | Adeyemi, Ganiyu (Chevron Nigeria Limited) | Okpani, Olu (Chevron Nigeria Limited)
This paper summarizes the strategy adopted in the development of two thin oil rim reservoirs in Okan Field, Offshore Niger Delta, Nigeria.
Its objective is to elucidate the strategy, engineering analyses, subsurface assessment and production procedures set in place to optimally develop the reservoirs.
Both reservoirs have oil thickness of <30 ft with gas thickness of >100 ft. The adopted development strategy for the two reservoirs involves the drilling of 4 wells, 2 in each reservoir, to drain the remaining oil reserves, prior to gas development.
Because of structural and fluid contact uncertainties, soft landing was incorporated into the well designs. Shale-to-shale correlation was used for accurate horizon depth prediction and detailed simulation models with local grid refinements were employed to determine optimum well orientation, landing depth, lateral length and aquifer properties. Details on their use to maximize value are shared.
While drilling, Azithrak™, a Baker Hughes tool, was used in geosteering the lateral well section to determine distance of well to nearest conductive zone as part of the oil-water contact tracking. All available data - logs, cuttings, reservoir pressures and production data - was incorporated and used to validate fluid contacts data because of the impact of landing depth relative to the fluid contacts on oil recovery. Simulation results and operational constraints were used to set acceptable production limits to ensure delivery of target reserves.
All the four wells have been successfully drilled and completed, with the wells landed successfully within the thin oil column, at the optimized distance from the fluid contacts, with the wells producing at <0.55 percent water cut. Initial production performances of the four wells are in line with static and dynamic assessment forecasts.
Lessons learned and challenges encountered during this development are also captured in this paper.