Most compositional reservoir simulation practices assumes that the compositions of various fluid components are the same at all locations within the reservoir system. This constant composition assumption is incorrect and unrealistic as it grossly ignores the occurrences of some less obvious physical processes in the reservoir. Gravitational force, temperature gradient and thermal diffusion, amongst other factors, contributes to distribution and gradation of hydrocarbon fluid compositions in the reservoir. Therefore, incorporating compositional grading models that Page 2 of 47 adequately accounted for the individual and combined effects of gravity force, temperature gradient, and thermal diffusion is crucial when initializing reservoir simulation models. This research seeks to elucidate the technical implications of compositional grading on improved reserve estimation and reservoir performance prediction. The mathematical framework for the compositional grading modeling is based on one-dimensional zero-mass-flow stationary state assumption. The Computer Modelling Group's equation of state multiphase equilibrium property simulator, WinProp, was used for the fluid modeling while Computer Modelling Group's compositional reservoir simulator, GEM, was used for the reservoir modeling and simulation. In the absence of historical production data, Computer Modelling Group's CMOST was used to perform uncertainty assessment for the validation of the initialized reservoir models. The research results show that initialized reservoir models that neglected or inadequately accounted for compositional grading effects, overestimated oil in-place and underestimated gas in-place. Constant composition (without compositional grading) initialized reservoir model overestimate ultimate cumulative oil production by 14.271 MMbbl more than the isothermal compositional grading model, and 24.088 MMbbl more than the Kempers thermal diffusion compositional grading initialized reservoir model. It underestimated ultimate cumulative gas production by 30.133 Bft 3 less than the isothermal compositional grading, and 50.408 Bft 3 less than the Kempers thermal diffusion compositional grading initialized reservoir model. These figures suggest that neglecting compositional grading or inadequate account of compositional grading effects in reservoir simulation initialization, has detrimental technical consequences.
Infill opportunity identification in a mature reservoir has some unique challenges because of the uncertainties in exact fluid front movement. These uncertainties are magnified for waterflood or gas-flood reservoirs. The reservoir of interest is a saturated oil reservoir with 54 years of production history and under waterflood. The aim of this study was to validate with a dynamic simulation model, infill opportunities proposed from using a combination of map-based assessment and current reservoir production data. High-resolution reservoir characterization was done to properly capture the different stratigraphic units in the reservoir. Insights from production and pressure behavior formed part of the input during the characterization phase. Results of the characterization step were used for earth modelling to generate a base case earth model for the reservoir used for history matching. Pro-cycling of the model was done during the history matching process, enabling the narrowing of fluid-in-place uncertainties during history matching. This resulted in a high-quality history-matched model that replicated over 80 percent of the fluid contact movement observed over the production life of the reservoir. This model was then utilized to validate two proposed infill opportunities in the reservoir. A key lesson identified during the process is that the use of high-resolution reservoir characterization methods prior to the earth modelling stage ensures better tracking of fluid-front movement and better replicates observed historical data. Rapid cycling between the earth modeler and simulation engineer also delivers significant value, by helping to resolve history-matching challenges early on and ensuring alignment between the dynamic model and the static interpretation of the reservoir.
The reliability of dynamic simulation models can spell the difference between value creation or erosion during the development of a hydrocarbon reservoir. There is a strong need to use every available data during reservoir characterization, earth modelling and history matching of the production and pressure history of the reservoir. Of greater importance is the need to blind test the history-matched simulation model, to ascertain its reliability, especially when the model is to be used for further development of the reservoir. This paper details an offshore Niger Delta case study in which saturation logging results were used to blind test a history matched model, with an objective to further validate the model. The saturated oil reservoir was fully characterized using high resolution sequence stratigraphy and the earth model developed with available static data. History matching of the dynamic model was carried out using the parameter estimation approach, incorporating available dynamic data and tracking of contact movement observed in post-production wells. Following the history match, a saturation log was run in one of the producers in the reservoir, as a blind test for the quality of the history match. Results of the log matched the contacts in the dynamic model within 1 ft, in the subject well, providing additional confidence in the quality of the model. As a result, matched model has been used for the maturation of 2 new drill opportunities with significant estimated recoveries.
The use of cement packers to access behind-pipe hydrocarbon opportunities has opened up significant reserves without the attendant cost of a rig. A key challenge with this technique is the attendant high skin that results from the cement packer which significantly impacts initial production rates and recoverable reserves. The objective of this paper is to share technique and lessons from a case study in a mature field, offshore Niger Delta where an innovative technique was employed to place the cement packer above the perforation interval in the target reservoir. This eliminated the skin due to the cement packer, leading to significantly higher initial production rates when compared to analog workovers. The paper details operational procedure during execution. The lack of a local precedent in the deployment of this type of cement packer presented a key challenge. Perforating the target reservoir and string without impacting the second string in the wellbore was another challenge. The initial production rate from the case study was 2200 BOPD vs 800 BOPD or less from analog cement packer workovers. A key lesson learned is that this solution is best suited to wellbores with a single production string only or multiple strings wellbores in which there is no further production utility for the additional strings. The follow on best practice from this lesson is to fully evaluate the wellbore utility for any identified opportunity of this sort to ensure the deployment of this method does not impede the utility of the wellbore for future reservoir management operations.
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.
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