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Collaborating Authors
An Integrated Approach to Optimize Field Development Plan Based on Uncertainty Analysis in a Giant Offshore Field
Zhao, Wenyang (ADNOC Offshore) | Al-Neaimi, Ahmed Khaleefa (ADNOC Offshore) | Sarsekov, Arlen (ADNOC Offshore) | Saif, Omar Yousef (ADNOC Offshore) | Abed, Abdalla Abdel (ADNOC Offshore) | Al-Feky, Mohamed Helmy (ADNOC Offshore)
Abstract With an increased maturity and complexity of the reservoir, an optimized field development plan implementation is critical to achieve the planned target and to ensure an optimum field recovery. The paper presents an optimized process with uncertainty analysis based on Monte Carlo Simulation for the purpose of optimizing the Medium Term Development Plan (MTDP) implementation. The five year development plan of this giant offshore field has been successfully assessed based on this optimized approach. The integrated workflow consists of four main parts, including actual field technical rate tracking, DBC optimization, simulation results, and effective capacity with Monte Carlo simulation embedded. The dynamic situations could be taken care with these seamless coupled tools. The actual field technical rate has been tracked on a monthly base through a systematic and automated process. The reference decline ratio has been assumed based on historical production decline analysis. Besides, a floating decline based on simulation results is also added in order to capture the well closure due to gas production limitation. Field technical rate is the fundamental input for field development plan to derive the field sustainable oil production rate. It is dependent on both existing wells' performance and future wells' planning. Both the expected gain and drilling schedule of the planned wells are crucial to achieve the production target with reservoir pressure appropriately supported. Voidage Replacement Ratio has been applied to balance production and injection. Drilling plan could be revised accordingly. The production and injection balance can be visualized in the effective capacity tool, which will be used to further optimize the producer and injector plans. The requirements of producers and injectors are summarized and imported into the DBC optimization tool to evaluate new drilling schedule, which will be used in the effective capacity tool for an iteration loop. Uncertainty analysis is critical to assure a field development plan. Uncertainties have been evaluated based on the factors' most probable range. Five major assumptions, including expected gain from new wells, drilling duration, decline ratio, put-on-production time, and operating efficiency, have been evaluated to assess the uncertainty. Mitigation actions could be proposed to assure the production plan.
Numerical Simulation of Dynamic Stress Field of Fractured Horizontal Well in Carbonate Reservoirs - In the Production Process
Wei, Shiming (China University of Petroleum) | Chen, Mian (China University of Petroleum) | Jin, Y. (China University of Petroleum) | Lu, Yunhu (China University of Petroleum) | Liu, X. (China University of Petroleum) | Wen, H. (China University of Petroleum)
ABSTRACT: Understanding the dynamic behavior of stress field during the production period helps to better design the production measures and engineering parameters of the following refracturing treatment. Based on the theory of pore elasticity, a production induced stress model was built. Combined with the field seismic and fracturing data, a geometric model of multi-fractured horizontal well in carbonate reservoir is established. Taking a well in Ta’ he oilfield as an example, the accuracy of the model is verified by actual production data. Through the simulation results, the model can accurately calculate the pore pressure and stress field distribution of carbonate rock formation during production process, then the minimum principal stress around the wellbore was analyzed. This study is instructive for uncovering the factors that affect the induced stress field during the production process. The results are also of great value for the optimization of refracturing treatment.
Abstract A technique for the efficient modelling of horizontal and undulating well trajectories is presented. In order resolve the fluid saturation and pressure, the layer containing the undulating wel1bure is refined in the vertical direction. The undulating wellbore is then represented by a series of discrete, cylindrical well bore segments which arc parallel the principal grid directions. The pressure drop and liquid holdup within the wellbore are determined through a material balance equation and multiphase pipe flow correlation. Several examples illustrating the application of this method are given for the modelling of undulating well trajectories. A comparison between the source/sink model and the discretized wellbore model for undulating wells is made. It is demonstrated that the discrelized wellbore model should be used when the total wellbore pressure drop is comparable to the drawdown pressure. The effect of capillary pressure is also examined for several different well trajectories. Finally, the effect of well trajectory for the production from a thin oil column with bottom water drive and a gas cap is examined. Introduction Interest in horizontal well has increased dramatically in recent years due to improved drilling technology and increased efficiency and economy of oil recovery operation. This improvement results from the extensive contact between the reservoir and the horizontal well giving rise to lower fluid velocities around the wellbore, while providing economical total flow rates. There are three methods used to represent horizontal wells in reservoir simulation. The first approach is the source/sink representation. This method is applicable when the frictional pressure drop along the wellbore is small compared to the well drawdown pressure. Furthermore the line source/sink method can yield erroneous results when wellbore backflow occurs or when the reservoir permeability is high due to the presence of fractures. The second approach is very comprehensive and requires the simulations solution of equations of the conservation of mass, momentum and energy in the wellbore together with the reservoir bore and its vicinity is important for accurate predictions. Because of the comprehensive treatment of the wellbore, the computational cost of this approach is high and therefore may be prohibitive simulations it may not be necessary to model the detailed flow phenomenon in the wellbore. A good approximation of the pressure drop phase saturation and composition distribution in the wellbore usually surfaces. The third approach termed "the diserenzed wellbore model", couples the wellbore and reservoir flow equations by edaciously casing the wellbore flow equation in a form similar to the reservoir flow equations. Thus, efficient numerical techniques that have been developed for reservoir simulation ncan be used to accurately model the wellbore flow. In reality, horizontal wells are not perfectly horizontal and can have complex well trajectories. These well trajectories can result in either slanted or undulating wells. For typical cases the horizontal well trajectory can vary by as much as ±5 m. Figure 1 shows a schematic representation of such an undulating well.
Abstract A technique for the efficient modelling of horizontal wells in reservoir simulation is presented. This technique treats the horizontal well as a second "porosity" as in the dual-porosity approach for naturally fractured reservoirs. The well "permeability" and "relative permeabilities" life adjusted to yield the pressure drop and phase slip predicted from multiphase flow correlations. Because the wellbore flow equations are cast into the same form as the reservoir flow equations, efficient techniques that have been developed for reservoir simulation can readily be applied. Examples illustrating the application of this method are given for the prediction of the performance of a horizontal well in a reservoir where water and gas coning are important. A validation of the model is provided by comparing oil rates and cumulative oil produced with results obtained from a line source-sink representation of the wellbore and comparing pressure drop and slip with results from a two-phase flow correlation for a case where the wellbore pressure drop is relatively small. Introduction Recent interest in horizontal wells has been rapidly accelerating because of improved drilling technology, and the inereased efficiency and economy of oil recovery operations. A recent report by Karisson and Bitto indicated that since the early 1980s, there have been more than 700 horizontal wells drilled with approximately 200 of those in 1988. The improvement in recovery and economics obtained with a horizontal well results From the extensive contact with the reservoir. This results in lower fluid velocities around the wellbore, while providing total flow rates which are economic. Typical applications of a horizontal well include:Reservoirs where conventional wells have low productivity; the use of horizontal drilling can be viewed as a method for well stimulation. Reservoirs where recovery is limited by water coning or gas cusping. This occurs usually when a thin oil column is sandwiched between a gas cap and an aquifer. The use of horizontal wells in this case lowers the pressure gradient near the wellbore and therefore reduces the water coning and gas cusping tendencies while allowing an economical production rate. Reservoirs with vertical fractures. Horizontal drilling allows the intersection of many vertical Fractures which Form the main now paths in the reservoir. Heavy-oil and tar-sands reservoirs where steam-assisted gravity drainage (SAGD) is practical. The process consists of injecting steam into an upper well and using a lower horizontal well as a producer to collect the draining oil and condensate from the steam chamber. Because the drilling costs of horizontal wells are 1.4 to 4 times more than those of vertical wells, it is imperative to conduct a reservoir engineering study of the recovery economics of horizontal wells before drilling. A reservoir simulator with horizontal-well capabilities can provide guidance into the design of well lengths, locations, optimal flow rates to prevent water coning or gas cusping and can predict the increa5c in recovery over that of conventional wells.
Abstract The technology of horizontal, multilateral and ERD wells has come from outer edge to mainstay in redevelopment of Mumbai High. The paper focuses on the technological improvements in engineering, placement and drilling of horizontal and multilateral wells, both infill and sidetrack, to exploit the bypassed, un-swept / less depleted reserves in the heterogeneous multi-layered carbonate reservoir. Mumbai High field, located in western continental shelf of India, is on production since 1976 and is the largest contributor to indigenous oil production. The field comprises of several pay zones of which "P" reservoir of early middle Miocene age is the major multi-layered limestone reservoir characterized with widely varying petrophysical properties. After attaining a production of about 400,000 bopd during 1985–90 the field had entered in declining phase. The problems of differential depletion and preferential water movement in the sub-layers, gas and water channeling /cusping occurred in the reservoir effecting the sweep efficiency. Based on the re-assessment of the reservoir with updated geological model and reservoir simulation an extensive footage campaign was launched in 2001 as a "redevelopment" IOR project. During implementation, various test experiments have been conducted on on-going basis and better strategies are being evolved. With successful application of enhanced drilling technology of horizontal, multilateral and ERD wells, and particular emphasis on targeting individual layers within the "P" reservoir, the declining production trend has already been reversed in the initial implementation phase. Oil production is showing an encouraging upward trend and an additional upside of the projected reserves is becoming visible. The paper highlights the approach followed for managing the reservoir with emphasis on absorption of emerging technologies. Analysis of gain in productivity due to new well engineering associated with layer thickness, heterogeneity and drainage pattern have also been discussed in the paper with the future scope for tapping the more difficult reserves and improving oil recovery in cost effective way through high tech wells. Introduction The Mumbai High field, the largest offshore oil field of India, was discovered in 1974. The field is situated in Western continental shelf towards west north west of Mumbai city at an average water depth of about 75 m. The field consists of heterogeneous, multilayered carbonate reservoirs. Being on continuous production for last 27 years, the field is in mature stage of its producing life. The level rate of oil production from the field was of the order of 0.4 million bopd during 1985 to 1990. During mid and late nineties the field had entered a crucial phase of "mid-life crisis" and production level dropped to about 0.21 million-bopd levels with rise in gas oil ratio and water cut. The oil recovery was about 20 %. To offset the declining trend and improve recovery, a "redevelopment" program was initiated during 1998–99. Reservoir re-evaluation was carried out through integration of G&G data and comprehensive review and analysis by the multi-disciplinary teams. Pilots were conducted to assess the potential of by-passed oil areas and to examine the feasibility of oil drainage from the area below the gas-cap through successful placement of the drainhole in thin zones using the new generation direction drilling tools and redesigned mud system. The refined reservoir characterization, use of state of the art technology for visualization of sub-surface complexities in immerse environment and changes in development pattern have facilitated to revitalize the field. The overall impact, even with limited implementation of the redevelopment program, has been very encouraging. Geological Description Mumbai High is a doubly plunging anticline structure with large areal extent. The hydrocarbon bearing carbonate formations are developed from Oligocene to Miocene with few regression and transgression cycles of deposition. The reservoir is bounded on the east by a major NNW- SSE trending fault. The western limb of the structure is gentle and the limit is defined by OWC. There are two highs separated by an east west trending low permeability barrier. The northern part is called Mumbai High North (MHN) while the southern part is Mumbai High South (MHS) (Figure-1).
- Asia > India > Maharashtra > Mumbai (1.00)
- Asia > India > Maharashtra > Arabian Sea (1.00)
- Asia > India > Maharashtra > Arabian Sea > Bombay Offshore Basin > Mumbai High Field > L-V Formation (0.99)
- Asia > India > Maharashtra > Arabian Sea > Bombay Offshore Basin > Mumbai High Field > L-IV Formation (0.99)
- Asia > India > Maharashtra > Arabian Sea > Bombay Offshore Basin > Mumbai High Field > L-III Formation (0.99)
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