Infill Wells Research Articles

Casing During Drilling With Rotary-Steerable Technology in the Stag Field—Offshore Australia

Summary Originally discovered in 1993, the Stag oil field, located on the Northwest shelf of Western Australia, has produced more than 58 million bbl since production began in 1998 (Goodacre et al. 2000). The field is shallow (680 m subsea), encompassing highly unconsolidated and highly permeable sandstone. Reservoir depletion, unconsolidated rock, water breakthrough, and sand production have created conditions under which infill-drilling campaigns have become increasingly problematic in the Stag field in recent years. There have been numerous papers documenting the history of the Stag field (McDiarmid et al. 2001; Muecke et al. 2002; Wibawa et al. 2008). On three recent infill wells, the intermediate 12¼-in. intervals were drilled and cased with casing-while-drilling (CWD) technology with a rotary-steerable system (RSS). This was used to navigate wellbore congestion, to drill designer well paths to avoid "incoherencies" [a seismic attribute that is mappable and correlates with drilling problems (Chima et al. 2012)], to land the horizontal section, and then to drill horizontal tangent sections out to the initial reservoir penetration (liner point). The CWD applications progressed from a "new technology" trial to a stretch reach and performance goal, to finally successfully being used as a key enabling technology to drill a well that might otherwise be undrillable because of instability issues. The directional CWD 12¼-in.-hole intervals were drilled from just below the 13-⅜in. surface casing to the 9⅝-in.-casing point, building from 25° inclination to horizontal and holding thereafter. This program (the first applications of this type in Australia) resulted in two consecutive world-record runs. The result is that CWD is a viable enabling technology that will be used to drill future Stag infill wells and should be considered as a viable alternative on other drilling projects. This paper will discuss the identification of the technology application, planning, implementation, results, and lessons learned. This paper will end with a notional conversation regarding CWD becoming a mainstream method.

Integration of surface seismic, microseismic, and production logs for shale gas characterization: Methodology and field application

Technologies such as horizontal drilling and multistage hydraulic fracturing are central to ensuring the viability of shale oil and gas resource development by maximizing contact with the most productive reservoir volumes. However, characterization efforts based on the use of well logs and cores, although very informative, may be associated with substantial uncertainty in interwell volumes. Consequently, this work is centered around the development of a predictive tool based on surface seismic data analysis to rapidly demarcate the most prolific reservoir volumes, to identify zones more amenable to hydraulic fracturing, and to provide a methodology to locate productive infill wells for further development. Specifically, we demonstrate that surface seismic attributes such as [Formula: see text]/[Formula: see text] crossplots can successfully be employed to quantitatively grade reservoir rocks in unconventional plays. We also investigate the role of seismically inverted Poisson’s ratio as a fracability discriminator and Young’s modulus as an indicator of total organic carbon richness and porosity. The proposed predictive tool for sweet spot identification relies on classifying reservoir volumes on the basis of their amenability to fracturing and reservoir quality. The classification scheme is applied to a field case study from the Lower Barnett Shale and we validate these results using production logs recorded in four horizontal wells and microseismic data acquired while fracturing these wells. The integration of seismic data, production logs, and microseismic data underscores the value of shale reservoir characterization with a diverse suite of measurements to determine optimal well locations and to locate hydraulic fracture treatments. A key advantage of the methodology developed here is the ease of regional-scale characterization that can easily be generalized to other shale plays.

Impact of natural fractures in drainage volume calculations and optimal well placement in tight gas reservoirs

Current practice of well placement in tight gas reservoirs generally involves the use of empirical correlations based on reservoir properties and analysis of past production histories and/or pressure maps from flow simulation. No rigorous procedure is available to compute well drainage volumes in the presence of heterogeneity controlled by the distribution and orientation of natural fractures. The situation is complicated by the routine use of complex wells in tight gas reservoirs and the presence of multistage hydraulic fractures. The computation of drainage volume will be critical to our understanding of the interaction between existing wells, potential infill locations and the estimated ultimate recovery (EUR) computations. We propose a rigorous approach for well drainage volume calculations in tight gas reservoirs based on the flux field derived from dual porosity finite-difference simulation and demonstrate its application to optimize well placement. Our approach relies on a high frequency asymptotic solution of the diffusivity equation and emulates the propagation of a ‘pressure front’ along gas streamlines. The proposed approach is a generalization of the radius of drainage concept in well test analysis (Lee, 1982). The method allows us not only to compute rigorously the well drainage volumes as a function of time but also examine the potential impact of infill wells on the drainage volumes of existing producers. Using these results, we present a systematic approach to optimize well placement to maximize the EUR. We demonstrate the power and utility of our method using both synthetic and field applications. The synthetic example is used to validate our approach by establishing consistency between the drainage volume calculations from streamlines and the EUR computations based on detailed finite-difference simulations. We also present comparison of our approach with analytic drainage volume calculations for simplified cases. Finally, we present a field example whereby we utilize the streamline-based drainage volumes to identify depleted sands and generate a reservoir ‘depletion capacity’ map to optimize infill well placement based on the undepleted and undrained regions. The field application clearly demonstrates a systematic approach to optimal well placement in tight gas reservoirs.

Scheme to Tap Remaining Oil Potential in Poor Pay Zones

This paper analyzed the balanced flood performance of various layers and the remaining oil distribution through numerical simulation technique. It shows that, the main remaining oil type of intended layers is caused by voidage-injection imperfection. Considering the needs of the follow-up infill well pattern and tertiary oil recovery, we decide to maintain the relative independence and integrity of each well network without disturbing the pattern configuration and the mining exploit object of various sets of well pattern. Finally we confirm to perforate adding the first infill wells of intended layers to consummate the water flooding regime. Through analyzing the production target of different well pattern optimization programs relatively, it shows that the best program has regular well pattern and large drilled thickness.

Technology Focus: Multilateral/Extended Reach (May 2013)

Technology Focus The producing assets of unconventional shale-gas and shale-oil plays in North America are among the strategic alternatives for future growth of exploration-and-production companies. Although the economics of the unconventional plays was quite marginal at the beginning, further advancements in planning and operations have made feasible the exploitation of such assets with a reasonable return on investment. The use of horizontal drilling in conjunction with hydraulic fracturing has expanded the ability of operators to recover natural gas and oil from low-permeability geologic plays in a profitable way. However, there is still room for improvement in efficiency. The exploitation of the unconventional areas with the current number of wells per acre and the amount of water used for the fracturing jobs is counterproductive. The current reality imposes fewer wells per acre, a reduction in drilling pads, and a minimum use of water in fracturing jobs. The implementation of multilateral, extended-reach, or fishbone wells is playing an essential role in the reduction of the wells, meanwhile maintaining or improving the production and recovery per acre. Thanks to the development of a new generation of fluids that improve hydraulics and wellbore stability, those wells can now reach targets farther from drilling centers, with a substantial increase in recovery and productivity per well. The selected papers give a perspective on the challenges faced on these well profiles and the technologies used to overcome them. On the other hand, the fracturing treatment has reached a considerable number of stages because of the long extension of the wells, resulting in a required water volume that has jeopardized the economics of the project and created problems with the local communities. The environmental effect of the wastewater from the fracturing jobs has brought concerns, urging the development of techniques that reduce the amount of such water. The volume of water in fracturing jobs is directly proportional to the fluid-loss-coefficient property, so decreasing that will result in more-effective fracture propagation with less water. Some research projects with the new generation of fracturing fluids—some including the use of nanotechnology—are aiming for this objective of improving fracturing jobs with a substantial reduction in water volume. The implementation of this new generation of fracturing fluids with multilateral/horizontal/extended-reach wells has the potential to enable the exploitation of unconventional reserves around the world with minimum visual and environmental effect, diminishing substantially the criticism about current unconventional shale operations. Recommended additional reading at OnePetro: www.onepetro.org. SPE 162099 Drilling World-Class ERD Wells in the North Caspian Sea by Sergey Bogdanov, Lukoil, et al. SPE 161532 Drilling Multilateral Infill Wells for Incremental Oil Production: A Case Study From a Mature Field by E. Zuckmeyer, Total, et al. SPE/IADC 163463 Extended-Reach Drilling—New Solution With a Unique Potential by O. Vestavik, Reelwell, et al.

인공신경망 시뮬레이터를 이용한 가스전 생산정 위치선정 연구

본 연구에서는 가스전의 추가 생산정 위치선정을 위해 고속의 연산이 가능한 인공신경망을 이용하여 저류 전산시뮬레이터를 개발하였다. 입출력자료와 알고리즘을 설계하였으며, 개발한 시뮬레이터를 이용하여 가스전의 추가 생산정 위치선정을 위한 연구를 수행하였다. 입력값은 생산시간, 생산정간 상관관계, 추가 생산정 위치좌표, 생산성 잠재력, 함수적 연관관계, 저류층 압력으로 구성하였으며, 출력값은 생산량과 함께 공저압력을 동시에 사용하였다. 20가지의 생산정 위치 시나리오에 대해 학습을 수행한 결과, 생산량의 상관계수 값은 0.99, 공저압력은 0.98로 상관관계가 매우 높은 것으로 확인되어 인공신경망 시뮬레이터의 타당성이 검증되었다. 가스전에서 최대공급계약량 유지시점을 산출함으로써 생산정 위치에 따른 생산성을 분석하였다. 그 결과 시나리오 C-1이 최대공급계약량 유지기간이 가장 짧았으며, 시나리오 A-1이 가장 오랫동안 유지시킬 수 있는 것으로 산출되었다. 결론적으로, 시나리오 A가 생산성에 영향을 받는 인자를 포함한 시나리오 B, C보다 최대 21% 더 최대공급계약량을 유지시킬 수 있는 것으로 확인되었다. 따라서 생산성에 영향을 미치는 요소를 종합적으로 고려하여 생산정의 위치를 선정해야 생산량을 극대화 할 수 있다. 본 인공신경망 시뮬레이터를 이용 시 생산기간동안 생산량과 공저압력 변화를 동시에 비교 분석하는 것이 가능하여 다양한 최적화 모델에 전위모델로 사용하는 것이 가능하다. This study presents development of the ANN simulator for well placement of infill drilling in gas fields. The input data of the ANN simulator includes the production time, well location, all inter well distances, boundary inter well distance, infill well position, productivity potential, functional links, reservoir pressure. The output data includes the bottomhole pressure in addition to the production rate. Thus, it is possible to calculate the productivity and bottomhole pressure during production period simultaneously, and it is expected that this model could replace conventional simulators. Training for the 20 well placement scenarios was conducted. As a result, it was found that accuracy of ANN simulator was high as the coefficient of correlation for production rate was 0.99 and the bottomhole pressure 0.98 respectively. From the resultes, the validity of the ANN simulator has been verified. The term, which could produce Maximum Daily Quantity (MDQ) at the gas field and the productivity according to the well location was analyzed. As a result, the MDQ could be maintained for a short time in scenario C-1, which has the three infill wells nearby aquifer boundary, and a long time in scenario A-1. In conclusion, it was found that scenario A maintained the MDQ up to 21% more than those of scenarios B and C which include parameters that might affect the productivity. Thus, the production rate can be maximized by selecting the location of production wells in comprehensive consideration of parameters that may affect the productivity. Also, because the developed ANN simulator could calculate both production rate and bottomhole pressure, respectively, it could be used as the forward simulator in a various inverse model.

Techbits: Wellbore Collision Avoidance and Interceptions - State of the Art

Techbits This article highlights key knowledge that was shared at the SPE’s “Collision Avoidance and Well Interceptions Applied Technology Workshop” held in Inverness, United Kingdom, in September. It raised awareness of issues concerning wellbore collisions and interceptions. Planning to ensure that well collisions do not occur during drilling is a complex and demanding task that is often not given the high priority that it requires in drilling programs. Assumptions are made of the validity and accuracy of historical data that is unfounded. Conversely, planning well interceptions when required in operations such as relief wells/drainage intercept wells requires a sound working knowledge of wellbore-positioning technologies and techniques. Wellbore interceptions and proximity placement are becoming critical applications for the development of some reservoirs, specifically tar sands and coalbed methane. Wellbore collision avoidance is entering the daily skills requirement of drilling engineers as they plan more infill wells and more cluster (pad) drilling. Ultimately, demonstrating the knowledge of the borehole position during the drilling process is becoming a regulatory requirement that demands greater understanding by the drilling engineering community and drilling/asset managers. Are drilling engineers trained, competent, and adhering to procedures designed to manage the intricacies of wellbore surveying requirements as applied to collision avoidance and well interceptions? The workshop covered the topic under the headings: Survey-database integrity Collision-avoidance management Practical directional drilling Relief-well design Interception techniques The workshop emphasized that wellbore collisions must be treated as high-risk events that must be managed by systematic survey-management procedures. Borehole-position errors are a critical input to subsurface modeling and have a major effect on field economics. Several workshop committee members are also members of the SPE Wellbore Positioning Technical Section (SPE WPTS) that has published two SPE papers on the ellipse of uncertainty error models commonly referred to as the Industry Steering Committee on Wellbore Survey Accuracy (ISCWSA) models. Summary of the Workshop Workshop attendees shared and learned about current good practices of the complete management cycle of well-positioning activities. Planning, policies, data management, practical application, and technology were all addressed. This was accomplished during presentations, discussions, and breakout sessions with industry experts. Some in-depth presentations and insightful results were produced, including good practice in designing a survey program requirements for survey-database management managing anticollision risk practical insights into relief-well planning and drilling

Optimisation and economical evaluation of infill drilling in CSG reservoirs using a multi-objective genetic algorithm

Water production in the early life of Coal Seam Gas (CSG) recovery makes these reservoirs different from conventional gas reservoirs. Normally, a large amount of water is produced during the early production period, while the gas-rate is negligible. It is essential to drill infill wells in optimum locations to reduce the water production and increase the gas recovery. To optimise infill locations in a CSG reservoir, an integrated framework is developed to couple the reservoir flow simulator (ECLIPSE) and the genetic algorithm (GA) optimisation toolbox of (MATLAB). In this study, the desired objective function is the NPV of the infill drilling. To obtain the economics of the infill drilling project, the objective function is split into two objectives. The first objective is the gas income; the second objective is the cost associated with water production. The optimisation problem is then solved using the multi-objective solver. The economics of the infill drilling program is investigated for a case study constructed based on the available data from the Tiffany unit in San Juan basin when gas price and water treatment cost are variable. Best obtained optimal locations of 20 new wells in the reservoir are attained using this optimisation framework to maximise the profit of this project. The results indicate that when the gas price is less than $2/Mscf, the infill plan, regardless of the cost of water treatment, is not economical and drilling additional wells cannot be economically justified. When the cost of water treatment and disposal increases from $0.01/STB to $4/STB, the optimisation framework intelligently distributes the infill wells across the reservoir in a way that the total water production of infill wells is reduced by 26%. Simulation results also indicate that when water treatment is an expensive operation, lower water production is attained by placing the infill wells in depleted sections of the coal bed, close to the existing wells. When water treatment cost is low, however, infill wells are freely allocated in virgin sections of the coal bed, where both coal gas content and reservoir pressure are high.

Seismic History Matching of Fluid Fronts Using the Ensemble Kalman Filter

SummaryTime-lapse seismic data provide information on the dynamics of multiphase reservoir fluid flow in places where no production data from wells are available. This information, in principle, could be used to estimate unknown reservoir properties. However, the amount, resolution, and character of the data have long posed significant challenges for quantitative use in assisted-history-matching workflows. Previous studies, therefore, have generally investigated methods for updating single models with reduced parameter-uncertainty space. Recent developments in ensemble-based history-matching methods have shown the feasibility of multimodel history and matching of production data while maintaining a full uncertainty description. Here, we introduce a robust and flexible reparameterization for interpreted fluid fronts or seismic attribute isolines that extends these developments to seismic history matching. The seismic data set is reparameterized, in terms of arrival times, at observed front positions, thereby significantly reducing the number of data while retaining essential information. A simple 1D example is used to introduce the concepts of the approach. A synthetic 3D example, with spatial complexity that is typical for many waterfloods, is examined in detail. History-matching cases based on both separate and combined use of production and seismic data are examined. It is shown that consistent multimodel history matches can be obtained without the need for reduction of the parameter space or for localization of the impact of observations. The quality of forecasts based on the history-matched models is evaluated by simulating both expected production and saturation changes throughout the field for a fixed operating strategy. It is shown that bias and uncertainty in the forecasts of production both at existing wells and in the flooded area are reduced considerably when both production and seismic data are incorporated. The proposed workflow, therefore, enables better decisions on field developments that require optimal placement of infill wells.

Numerical Simulation Optimization Study on Adjusting Well Pattern and Productive Series in Xingqi Area

In order to optimize space of tertiary infill wells and tertiary recovery wells, this paper applies numerical simulation method to study Xingqi Area in Daqing oil field. According to serious lateral and vertical heterogeneity and different control degree of water flooding in different parts of reservoir, 3 development schemes are designed. Numerical simulation results show that Scheme 2 is the best, whose well pattern consists of tertiary infill wells and tertiary recovery wells. When water cut is 98%, the ultimate recovery reaches 58.66%, which is 10.74% higher than the ultimate recovery of old well pattern. The result possesses great theoretical guidance for the same kinds of reservoirs.

Practice and Theory of Restructuring Water Flooding Series in Sabei Oilfield

In Sabei Development Area, with the developments of oilfield infill wells, the production targets of each set of well nets went bad and had interleaved distributions with old well patterns. At the same time, polymer flooding well patterns made the conflict of cohesion and dynamic regulation outstanding. Especially, Beierdong, which was the earliest block using infill drilling modification, got the good development effect at beginning, however, with the progress of oilfield development, there were some troubles in the development period with extra high water, such as long section of perforation, obvious inconsistencies between formations and high water of layers, which brought difficulties to dynamically adjusting. To fully exploit the remaining oil potential, this paper selected 1.30 km2 west blocks in Beierdong, made tests about sediment group restructuring to improve water flooding development effect, redistribute the series of strata and redistribute the flooding network according to the characteristics of development between the layers, combined comprehensive consideration with follow-up adjustment such as primary network, injection production system and type II reservoir the tertiary oil production, optimized the layers combination and well patterns arrangement, finally formed technical ideas of high water cut layers adjustment and well nets evolution.

Infill-Drilling Potential in Tight Gas Reservoirs

Many operators of tight gas reservoir fields are interested in determining the infill well potential in these fields. Over drilling may prove to be uneconomical; whereas, under drilling would leave unexplored reserves under the ground. In predicting EUR (expected ultimate recovery) of a potential infill well, operators are interested in knowing what percentage of the production will be come from incremental reserves (newly accessed) and what percentage is from acceleration reserves (which can be produced from existing wells). So, higher the percentage of incremental reserves better is the potential of an infill well. In this paper, we present a novel method for determining the incremental versus acceleration potential for infill well in a tight gas reservoir. We evaluate the existing wells by plotting the data in a form so that the data can be linearly extrapolated. Then, we can predict the EUR for individual wells before and after new wells in the vicinity are drilled. By knowing how much gas is “diverted” from the older wells, we determine the acceleration component of an infill well. By repeating the process as the field is being developed, we can determine the fraction of acceleration and incremental components of the EUR at each stage of infill drilling. We will also know how the EUR is changing as the well spacing is slowly reduced. To ensure our results are reasonable, we also compare our EUR values with EUR’s reported by the operator as proved reserves. Armed with this information, we can extrapolate infill well potential for a smaller spacing, including the contribution due to acceleration versus incremental production. We applied this procedure for Wamsutter field in Wyoming. Using the procedure, we recommended infill well locations to the operator. Operator has drilled seven wells based on our recommendations. Using this new method, we can predict the EUR for infill well as well as acceleration and incremental contribution of the infill well. Thus, potential of infill wells at different locations can be evaluated and compared.

The Research of Flood Pattern Completeness in the Thin and Poor Oil Layers of South West II Area

As line well pattern is the main development technique in the thin and poor oil layers of Daqing Oilfield South West Ⅱ PⅠ group, the layers have been idle and the degree of reserve recovery is far less than the region level. In response to these problems, we analyzed the balanced flood performance of various layers and the remaining oil distribution through numerical simulation technique. It shows that, the main remaining oil type of intended layers is caused by voidage-injection imperfection. Considering the needs of the follow-up infill well pattern and tertiary oil recovery, we decided to keep the well network independent and integrated without disturbing the pattern configuration and main mining object of various sets of well pattern. Finally we confirmed to perforate-adding the first infill wells of intended layers to consummate the water flooding regime. Through analyzing the production target of different well pattern optimization programs relatively, it shows that the best program has regular well pattern and large drilled thickness.

Optimizing well placement in a coalbed methane reservoir using the particle swarm optimization algorithm

The optimization of well placement in a coalbed methane (CBM) reservoir is challenging and intricate work due to the large number of variables and geological uncertainties. To address these challenges, this paper presents a framework that integrates a reservoir simulator into the particle swarm optimization (PSO) algorithm. The application of the PSO algorithm can greatly reduce optimization time and work volume. In this study, optimizations were conducted of the placement of single and multiple wells by maximizing net present value (NPV) in a synthetic reservoir. The optimizations tracked a field application in a CBM district located in the southeast of Ordos basin.A comparison of optimal well placements, which were determined by the PSO and manual trials respectively, showed complete concurrence for a single well. The effect of swarm size on the convergence speed to an optimal location was analyzed. The results indicated that a minimum swarm size of 10 particles is required to guarantee convergence to the global optima. For the case of multiwell placement, we compared the NPV of the optimized well placement determined by the PSO with 1200 randomly selected well placements and found that none of the randomly set wells surpassed the optimized well placement. The optimization results indicated that higher permeability and well interference have a positive effect on the optimal location.After history matching, the rearrangement of 10 vertical wells and an optimization of infilling scenarios were performed in a 5-year-old CBM district located in the southeast of Ordos basin. The optimization results demonstrated that cumulative gas production (CGP) increased by 22.01%, while cumulative water production (CWP) remained nearly unchanged after optimization. Optimal locations tend to be in regions with higher permeability and/or gas content. The NPVs in six infill scenarios exhibited an initial increase, but later exhibited a decline as the number of infill wells increased from zero to seven. A peak NPV value occurred at one infill well.

The Evaluation of Gas, Water, WAG Injections, and Infill Wells for Improving Recovery of an Iranian Reservoir

Increasing demand for energy has forced oil companies to resort to secondary and tertiary methods to increase the recovery from the existing reservoirs. The author investigated enhancing the recovery factor of one Iranian reservoir, which is a naturally fractured reservoir. For this reservoir, it is estimated that 96.5% of oil is contained in the matrix and 3.5% in the fractures. The field is an undersaturated reservoir with no active gas cap and no strong water aquifer. Injections of water, gas, water-alternating gas (WAG), and infill wells on this field were investigated to increase the recovery factor. Eclipse100 was employed to simulate the reservoir. The simulated results showed that gas, water, and WAG injections had nonsignificant improvements on oil recovery. However, it was found that infill wells contribute an appreciable increase in recovery. The amount of increase for drilling 8 infill wells was around 5%. Since development of existing resources contributes a major role on the supply of oil for the future oil market (around 45% by 2030), these results are used to screen the various methods for increasing the recovery of such reservoirs.

A Productivity Evaluation Model and Its Application for an Infill Horizontal Well in Different Types of Reservoirs

Productivity evaluation for infill horizontal well should take into account the interference of other oil or water wells in the flooding pattern. On the basis of the mirror-image method and source-sink theory, a semianalytical model of productivity evaluation for infill horizontal well in different types of reservoirs was built, in which the effect of boundary, the interference of other wells, the randomicity of flooding pattern, and the pressure drop along the horizontal lateral were taken into account. Application of the novel semianalytical model has demonstrated its reliability and usefulness. It is an effective method for the productivity evaluation for infill horizontal well in different types of reservoirs.

Characterizing production‐induced anisotropy of fractured reservoirs having multiple fracture sets

ABSTRACTSince natural fractures in petroleum reservoirs play an important role in determining fluid flow during production, knowledge of the orientation and density of fractures is required to optimize production. This paper outlines the underlying theory and implementation of a fast and efficient algorithm for upscaling a Discrete Fracture Network (DFN) to predict the fluid flow, elastic and seismic properties of fractured rocks. Potential applications for this approach are numerous and include the prediction of fluid flow, elastic and seismic properties for fractured reservoirs, model‐based inversion of seismic Amplitude Versus Offset and Azimuth (AVOA) data and the optimal placement and orientation of infill wells to maximize production. Given that a single fracture network may comprise hundreds of thousands of individual fractures, the sheer size of typical DFNs has tended to limit their practical applications. This paper demonstrates that with efficient algorithms, the utility of Discrete Fracture Networks can be extended far beyond mere visualization.

Production-Induced Stress Change in and Above a Reservoir Pierced by Two Salt Domes: A Geomechanical Model and Its Applications

Summary Production decreases the pore-fluid pressure and increases the effective stress acting on the load-bearing-grain framework that makes up the reservoir. As a result, the reservoir deforms and compacts, and because it is connected to the rocks around it, there will be deformations and displacements in these rocks also. Well known geomechanical effects of production include surface subsidence, wells damaged by shear, and time shifts in 4D seismic. Less well known is how the changes in the stress field itself should be taken into account in operations—e.g., to design infill wells and to plan production stimulation by hydraulic fracturing or waterflooding of the reservoir. We present a geomechanical model for the initial stress field and production-induced stress changes in and around a steeply dipping hydrocarbon reservoir penetrated by two large salt domes. The model integrates 3D seismic and geological understanding, geomechanical data from wells and analogues, and depletion patterns from fluid-flow (dynamic) simulation. Our model results confirm published models of principal-stress orientation in rocks pierced by salt domes. The depleted-model results show stress changes up to several MPa in magnitude compared with the preproduction stress state, but only limited changes in the stress orientations. The model highlights the influence of structural dip and time-dependent salt/sediment interaction on stress changes. We then describe the application of the model in wellbore stress analysis for infill wells and in a water-injection scheme that has, we believe, been severely impacted by injection-induced fractures propagating in the reservoir from the injector wells toward the producer wells. We explain how the latter application uses a 3D flow-simulation model coupled to a dynamic fracture-propagation model. The geomechanical model provides key input: stress magnitude and stress orientation. Results are validated against a more conventional analysis of real-time pressure data. In both applications, the integration of geomechanics in 3D static and dynamic models improved insight into the rock response to drilling and waterflooding, thus helping to optimize production.

Advanced Drilling in HP/HT: Total's Experience on Elgin/Franklin (UK North Sea)

Technology Today Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering. Abstract Drilling high-pressure/high-temperature (HP/HT) exploration wells remains a challenge, despite years of experience acquired by the drilling/completion industry. Development wells have further expanded the envelope of performance of the technologies and procedures required to deliver production from HP/HT fields safely and economically. Now comes the time of drilling and completing infill wells, which paradoxically appear to be more difficult as depletion increases and the mud-weight window (MWW) diminishes. To overcome this problem, intense engineering work has been carried out to better understand the effect of the depletion on compaction and fracturing gradient, to design and qualify new drilling-mud systems combined with stress-caging techniques, and to prepare contingent solutions with the deployment of expandable- and drilling-liner technologies. Three infill wells have been drilled, completed, and put on production by Total in the Elgin/Franklin fields on the UK Continental Shelf. This success was achieved through severely depleted reservoirs—with depletion greater than 800 bar—and has enabled phased HP/HT developments and deep exploration beneath depleted horizons. Overview of the Elgin/Franklin Extreme-HP/HT Fields The Elgin/Franklin fields present an extreme combination of pressure and temperature (1,100-bar virgin pressure and 200°C, respectively) and remain the largest HP/HT gas/ condensate fields developed in the British sector of the North Sea. The fields are approximately 200 km northeast of Aberdeen in the Central Graben area. Following discovery and appraisal from 1985 to 1994, development started in 1996 with two unmanned wellhead platforms tied back to a central production facility. Eleven wells were drilled and put on stream, with deviations up to 50°, in an average drilling duration of 120 days. These wells were drilled before a predefined limit of depletion level had been reached, a level at which the MWW closes—calculated for Elgin/Franklin as 100 bar. First oil production occurred in 2001. Later, two satellite structures, Glenelg and West Franklin, were drilled and put on production through the existing installations in 2006 and 2007, respectively, (Fig. 1). The reservoirs consist of Jurassic sandstones buried at a depth exceeding 5300 m. The primary reservoir is the Fulmar, also called Franklin, sands. Reservoir fluids are gas/ condensate with a bottomhole pressure of 1100 bar and temperature of 190°C. The Fulmar reservoir is underlain by the Pentland reservoir with bottomhole conditions of 1150 bar and 200°C (Fig. 2). Despite the depth, the main reservoir shows significant porosity and permeability, allowing strong productivity. Up to 30% porosity and 1-darcy permeability are found in some Fulmar layers Individual wells in the field can produce up to 3.5×106 m3/d of gas with associated condensate. Surface production conditions are 860-bar wellhead shut-in pressure with an associated temperature of 180°C. The produced effluent contains 3 to 4% CO2 and 30 to 40 ppm H2S. Initially, field gas production reached 14.6×106 m3/d, with 24 000 m3/d of condensate. This combination explains the strong need for technology and in-depth engineering for these wells.

Fast and efficient sensitivity calculation using adjoint method for three-phase field-scale history matching

Adjoint method-based sensitivity for field-scale history matching with large numbers of parameters suffers from several limitations. First, the CPU time depends on the data points which are large for any brown fields of long history; second, it requires large memory to save the gridblock pressure and saturation per each time step used in the forward model. Third, it is computationally expensive as it requires solving the Adjoint system of equations backward in time per each forward time step which is usually of high magnitude in case of field scale applications of long history. Lastly, the solver used for solving the Adjoint system of equations needs to be efficient for large-scale applications. We propose an efficient and fast approach for sensitivity calculation based on the Adjoint method to overcome much of the current limitations. First, we use a commercial finite difference simulator, ECLIPSE, as a forward model, which is general and can account for complex physical behavior that dominates most field applications. Second, the production data misfit is represented by a single generalized travel time misfit per well, thus effectively reducing the number of data points into one per well. Third, we solve the Adjoint system of equations backward in time in a larger time step that is equivalent to the time of severe changes in pressure and saturation due to changing well conditions or introducing new infill wells rather than using the forward model time steps. This approach reduces the computational effort and memory allocated for the sensitivity calculation. Fourth, we use an iterative sparse matrix solver, LSQR, for solving the Adjoint system of equations which shows high stability for field-scale applications. We demonstrate the power and utility of our approach using synthetic and pseudo field examples. The synthetic examples show the robustness and efficiency of our sensitivity calculation approach compared to the perturbation. The pseudo-field example had 10 years of production history with an original gas cap and a strong aquifer support. Using well log data, core data, water cut and gas–oil ratio history from producing wells; we characterize the permeability at each cell, thus demonstrating the feasibility of our approach for field applications.