Optimal Infill Drilling Using Simulation and Cross-Functional Integration-Ubit Field Example

Practical workflow to improve numerical performance in time-consuming reservoir simulation models using submodels and shorter period of time

The computation of flowing-well bottomhole pressure from the pressure of the block containing the well or of well flow rate when the flowing bottomhole pressure is specified are important considerations in reservoir simulation. While this problem has been addressed by several authors, some important aspects of the problem are not treated adequately in the literature.We present an analytical method for computing the well-block factors (constants of the PI) for a well located anywhere in a square or rectangular block (aspect ratio between ½ and 2). Equations for well geometric factors and well fraction constants are given for gridblocks of various types, containing a single well, encountered in reservoir simulation studies. The equations given in this paper can be used for both block-centered and point-distributed grids in five- and nine-point two-dimensional (2D), finite-difference formulations. The radial flow assumption used in deriving the equations in this paper is not always strictly valid; however, for most practical situations it provides an adequate approximation for near-well flow.

The technology developed for massive hydraulic fracturing in tight gas reservoirs is applied to create short, highly conductive fractures in the oil productive Upper Clearfork formation of West Texas. The contents of this paper review operational aspects of design and factors influencing the successful execution of fracture treatments during an extensive infill drilling and waterflood expansion program in the Amoco operated Prentice Northeast Unit (PNEU). The PNEU is located in Terry and Yoakum counties of West Texas. Long Spaced Digital Sonic Log Data (LSDS) was collected on several wells in the Prentice Northeast Unit. This data, along with results of pump-in/flowback and mini-frac tests were used in conjunction with fracture design and economic models to develop an optimum fracture design for this reservoir. Fracture pressure analysis and post fracture pressure decline analysis techniques were used to further refine the optimum treatment design. The optimum fracture design, developed in this manner, was then used to stimulate over 60 wells in this Unit and other Amoco operated Units producing from the Upper Clearfork formation. Results of these fracture stimulations have been excellent. This paper presents a discussion of the collection of post-fracture pressure decline data, the analysis of this data, and the application to optimize the design of hydraulic fractures in the Upper Clearfork formation. Fracture stimulation design is presented with a framework in which maximization of return on the invested dollar is the ultimate goal.,

Monument Butte field produces oil from 22 commingled sandstone reservoirs across a 2200-ft interval of the Green River formation. Total (primary and secondary) recovery is less than 10% of the OOIP. Green River formation sands are lenticular, lacustrine fluvial-deltaic units that have limited aerial extent and vertical communication, resulting in poor interwell connectivity. Moreover, the reservoirs sands have low permeability. To determine interwell connectivity and to identify methods to improve oil recovery, we conducted detailed reservoir characterization and simulation studies in a pilot area of Monument Butte field. We built a 3D geostatistical model and ranked geological realizations using production history matching with streamline simulation. Detailed petrophysical and geological modeling were used to quantify interwell connectivity of sands as a function of well spacing. Studies of interwell connectivity were also used to identify flow barriers that we applied in upscaled reservoir simulation models to better represent interwell connectivity. A combination of manual and assisted history matching methods was used to calibrate the reservoir model. Primary, secondary, and tertiary development strategies were then evaluated for future optimization of oil recovery for new developing areas in Monument Butte field. This study yielded a reservoir model much improved over those of previous studies. A good history match was obtained for most wells, despite the complexity of this stacked, heterogeneous reservoir system. Simulation results indicate that interwell connectivity has the greatest impact on reservoir performance. Interwell connectivity was demonstrated for only major sands, and interwell connectivity increases as well spacing decreases for these sands. A pilot 20-acre infill drilling study is needed to verify this conclusion. The overall connectivity for the combined 22 zones is 0.056 (connected adjacent well pairs divided by total adjacent well pairs). The connectivities for major sand zones evaluated by history matching are 0.65, 0.16, 0.23, and 0.01 for the D1 sand, C sands, A sands, and LODC sands, respectively. Simulation results indicate that reservoir performance can potentially be improved with various reservoir management strategies, including infill drilling. For new development areas, water flooding should start as soon as possible (within 6 months). Tertiary recovery methods may have potential in the Monument Butte field, given the low recovery efficiencies for primary and secondary recovery. Water-alternating-CO2 injection appears to be superior to other tertiary recovery methods. Further evaluation and piloting of tertiary methods is required, given the connectivity risk. The target area study results can be used to guide the development of other parts of the large Monument Butte field.

A cooperative study of the Grayburg/San Andres reservoir is planned for the Foster and South Cowden Fields, Ector County, Texas under the U.S. Department of Energy's Class II Program for ShallowShelf Carbonate. The project will utilize existing technology to increase oil production through infi11dri11ing, workovers, and water flood development. Productivity problems associated with a mature shall owshelf carbonate reservoir will be addressed by a multidisciplinary tech­ ni cal team which integrates high resolution 3-D seismic data, reservoir characterization techniques, and 3-D reservoir simulation. A 3-D seismic survey designed specifically for i magi ng the Grayburg/ San Andres interval of the Foster and South Cowden fields will be acquired. A high performance computer work­ station will then be used to integrate existi ng subsurface geological and engineering data with the 3-D seismic data for a detailed evaluation of sequence strati graphy and facies relationships. Subsequentl y, a 3- D reservoir simulation model will use the results to hel pdefine flow units wi thin the reservoir. A field demonstrati on of in fill dri11ing and water flood deve1 opment wi11 follow. The high resolution 3-D sei smic survey is expected to resol ve changes in the subsurface on the megascopic scal e, al l owi ng for carre­ lation of pet rophysical properties and stratigraphic information between boreholes. This informati on will be helpful in mapping porosity zones, permeability barriers, and "thief" zones within the reservoir.

Rock typing is an essential part of building geologic model for an asset. Millions of dollars are invested in logs, core measurements, SCAL studies, and geological interpretation that result in definition of different rock types. Rock types overlap and do not have crisp boundaries.;Upon definition of rock types for a series of geological formations geoscientists use approximation of multiple and overlapping rock types to identify a dominant rock type for any grid block in a reservoir simulation model. This defeats the original purpose of performing detail geological, petrophysical studies as far as reservoir flow models are concerned.;The objective of this study is to develop a new and novel methodology based on performing "fuzzy rock typing". Fuzzy rock typing refers to application of fuzzy set theory to the part of reservoir characterization that is concerned with rock type determination. Fuzzy set theory is applied in order to take into account the inherent uncertainties and vagueness associated with rock typing in hydrocarbon bearing reservoirs.;In this work, a numerical simulator has been used as the control environment in order to set up multiple studies that would demonstrate the differences between using conventional (current practices) approach of implementation of geologic models in the reservoir flow simulation studies and the new approach that is the subject of this study. By using the numerical reservoir simulator as the control environment it is intended to study the complexities that exist in upscaling the high resolution geological model using two different approaches.;The high resolution geological model used in its entirety and the flow simulation is performed. The results (production profiles) are compared to first, the upscaled model using conventional (current) practices and then the upscaled model using the proposed technique. The results are analyzed in order to demonstrate the difference between the two techniques and the advantages and disadvantages of each have been identified.

This paper provides an overview of an advanced visualization system for visualizing giga-cell simulation models to assist Reservoir Engineers in managing and developing Saudi Arabia’s giant fields. The challenges in the hydrocarbon industry require the use of the latest technology to maximize recovery in a cost-effective manner. Over the last few years, reservoir simulation activities have undergone major transformation toward the use of giga-cell simulation models [1]. This transformation stems from the use of advanced data acquisition solutions and advanced modeling packages to capture and model physically large fields. Fine scale-grid blocks capture detailed description of geologic heterogeneity that is necessary to model the complexity of fluid flow in the subsurface. Giga-cell simulation models are currently generated using Saudi Aramco’s GigaPOWERS parallel reservoir simulator [2]. The size of reservoir simulation models continues to grow to exceed the billion-cell barrier. The design of a high performance computational platform for simulation of giant reservoir models has been discussed in other literature [3]. In this paper, we focus on the simulation post-processing visualization system developed, which consists of advanced technologies for handling and visualizing massive amounts of data. Implemented techniques include: Remote visualization utilizing graphics processing clusters, parallel data loading, level of detail graphics rendering and hierarchal multi-resolution data structure. In addition, a number of advanced visualization features that have been implemented are highlighted in this paper, such as the ability to display fluid patterns in the field by utilizing streamlines and vector fields, advanced volume visualization techniques based on streamlines and wells filtering to help engineers better understand the fluid flow in subsurface reservoirs. Furthermore, the performance considerations, challenges and impact on reservoir simulation studies are also discussed.

Summary A considerable portion of the world's hydrocarbon endowment is in carbonate reservoirs. Carbonate reservoirs usually exhibit low porosity and may be fractured. These two characteristics along with oil-to-mixed wet rock properties usually result in lowered hydrocarbon recovery rates. When enhanced oil recovery (EOR) strategies are pursued, the injected fluids will likely flow through the fracture network and bypass the oil in the rock matrix. The high permeability in the fracture network and the low equivalent porous volume result in early breakthrough of the injected fluids. Infill drilling programs and well conformance strategies—mostly gas and water shutoff—have been effectively used to mitigate the early breakthrough and increase oil recovery. In most cases, however, 40 to 50% of the original oil in place (OOIP) is not produced. A large number of EOR field projects in carbonate reservoirs have been referenced in the literature since the early 1970s. These field projects demonstrate the technical feasibility of various EOR methods in carbonate reservoirs. However, because of the collapse in oil prices, most of the aforementioned project plans have been abandoned. This paper presents a comprehensive compilation of EOR (Gas, Chemical, and Thermal methods) field experiences in carbonate reservoirs within the US, as an attempt to identify key variables and project design parameters for future evaluation and revitalization of mature carbonate reservoirs. Carbon dioxide flooding [continuous or water-alternating gas (WAG)] is the dominant EOR process used in the US This is because of the high availability of low-cost CO2. CO2 EOR in particular represents the logical first step towards viable geologic carbon storage and sequestration. EOR chemical methods in carbonate reservoirs, especially polymer flooding, have been widely tested in US carbonate reservoirs. However, EOR chemical methods have made a marginal contribution, relatively, in terms of total oil recovered. Our study includes a brief overview of current laboratory (e.g. wettability changes and novel chemical additives) and field (e.g. injectivity enhancement) experiences in EOR chemical methods in carbonate formations. A brief discussion surrounding the screening methods used to identify viable EOR opportunities in carbonate fields based on past and present experiences is also included. Introduction Carbonate reservoirs are naturally-fractured geologic formations characterized by heterogeneous porosity and permeability distributions. In the case of low porosity and low permeability carbonate rocks (more specifically rock matrices), the fluid flow in the reservoir can be completely dependent on the fracture network while the matrix only plays a source role (analogous to tight sand formations and natural gas flow). In the case of porous carbonate rocks, fracture networks can cause uneven sweeping of the reservoir, leading to early breakthrough of injected fluids in the producing wells and resulting in low recovery factors. The abundance of carbonate reservoirs has been the subject of numerous studies attempting to characterize their heterogeneities, classify different types of fractured reservoirs, and determine how rock and fluid properties have an impact on ultimate recovery (Roehl et al. 1985; Allan and Qing Sun 2003; Carr et al. 2001; Grave et al. 2000; Benson et al. 1998; Wardlaw 1996). The TORIS database (maintained by the US Department of Energy) indicates 22% of the OOIP in the US is contained in shallow-shelf carbonate reservoirs. Currently in the US, these types of reservoirs exist in more than 14 states with over 70% of the OOIP located in reservoirs in Texas and New Mexico, mostly concentrated in the Permian Basin (Nuckols 1992, Xie et al. 2005). Over the last three decades, primary production, waterflooding, and CO2 floods, combined with infill drilling programs, have been the most widely used recovery methods. However, other EOR strategies have been tested in the past and there are currently several active research programs seeking alternatives to increase the recovery factor of these mostly light crude-oil reservoirs economically. Although the Permian Basin (west Texas and southeast New Mexico) can be considered mature, its potential for improved oil recovery is still very high. A recent study reports that there is an estimated 30 billion barrels of mobile oil in the Permian Basin, reiterating the strategic importance of EOR technologies for carbonate reservoirs and their impact on US oil production (Nuckols 1992; Xie et al. 2005; Seethepalli et al. 2004; Moritis 2004; Cole 2003; Moritis 2003; Dutton et al. 2004).

A small-scale hydrocarbon miscible flood was initiated at the Kuparuk River Unit on the North Slope of Alaska in mid-1988, three years after the start-up of waterflooding. This Small Scale EOR (SSEOR) project, along with an infill drilling program, is improving recovery from a stratified and highly faulted sandstone reservoir. The project design was aided by limited compositional reservoir simulation. The design calls for the injection of a 30% hydrocarbon pore volume (HCPV) slug of miscible injectant (MI) which is injected alternately with water at a 1:1 water-alternating-gas (WAG) ratio for mobility control. An extensive laboratory program was conducted to understand the displacement process and to develop an equation of state (EOS) fluid characterization. The displacement process is characterized as a condensing/vaporizing gas-drive process, providing a high unit displacement efficiency. A comprehensive surveillance program was implemented to quantify reservoir continuity and vertical conformance. A gas tracer program has helped in interpreting the influence of faulting on interwell continuity and regional fluid flux. Injection and production well surveys indicate that permeability stratification controls vertical conformance. Preliminary evaluation of project performance indicates significant incremental recovery associated with both infill drilling and enriched gas injection. Typical EOR response includes a significant increase in the oil production rate, with an associated decreasing watercut and increasing gas-oil ratio.

Enhanced oil recovery in unconventional plays has been a focus of many E&P operators to increase recovery factors. Conventional displacement-based secondary (e.g. water flooding) and tertiary EOR methods are not viable options due to their low injectivity in these ultra-low permeability formations. As such, huff-n-puff (HnP) EOR techniques involving field gas injection may be the most effective EOR methods to increase the recovery factors from these shale formations. Several numerical reservoir simulation studies have showed the efficiency of CO2 HnP process in shale and tight formations (Yu et al, 2014); however, these studies show little to no field results to support the simulation predictions. This paper describes the conceptual development of the reservoir simulation models to investigate the viability of gas injection HnP in unconventional reservoirs and the results of applying those methods in Eagle Ford field test sites. Single-well and multi-well models with multi-stage hydraulic fractures were constructed and history matched using their primary production period performance. Sensitivity studies were conducted on well communication behavior/impacts, injection gas compositions, injection rates, injection/production cycling, and reservoir fluid types to optimize the pilot project well location(s) and to inform development strategies. Optimal cases from the simulation study were successfully applied to multi-well pads in the Eagle Ford formation across multiple fluid types. The simulation and the field application results were summarized and compared to provide detailed insights of unconventional HnP EOR. This study indicates the importance of confinement of the gases to afford optimal recovery factors during unconventional gas HnP EOR. An optimization engine was used in this study to optimize key operational parameters, such as injection pressures and slug sizes, to maximize recovery and efficiency. The resulting EOR designs were successfully implemented in field operations. Field recovery factors are within 10% of those predicted by simulation, indicating the value of numerical reservoir simulation prior to field trials and subsequent future development.

Y Field which located around 28 km south east of Jakarta was discovered in 1989. Three wells have been drilled and suspended. The initial gas ini place (IGIP) of the field is 40.53 BSCF. The field will be developed in 2011. In this study, reservoir simulation model was made to predict the optimum development strategy of the field. This model consisted of 1,575,064 grid cells which were built in a black oil simulator. Two field development scenarios were defined with and without compressor. Simulation results show that the Recovery Factor at thel end of the contract is 61.40% and 62.14% respectively for Scenarios I and II without compressor. When compressor is applied then Recovey Factor of Scenarios I and II is 68.78% and 74.58%, correspondingly. Based on the economic parameters, Scenario II with compressor is the most attractive case, where IRR, POT, and NPV of the scenario are 41%, 2.9 years, and 14,808 MUS$.

Традиционные подходы к разработке нефтяных месторождений на поздней стадии приводят к локализации значительного объема запасов нефти в межскважинном пространстве. В настоящий момент, существует целый ряд эффективных технологических решений, направленных на доизвлечение запасов нефти на действующих месторождениях. Одним из путей решения проблемы довыработки остаточных запасов нефти, сконцентрированных в слабодренируемых и застойных зонах, является уплотнение сетки скважин. В данной статье приведён пример технологических решений, направленных на уплотнение сетки скважин на карбонатных коллекторах Беркет-Ключевского нефтяного месторождения Республики Татарстан. Рассмотрены различные варианты по дальнейшей разработке залежи нефти с использованием геолого-гидродинамического моделирования. Показаны результаты прогнозных технико-экономических показателей разработки от предлагаемых технологических решений, направленных на увеличение степени выработки запасов в межскважинном пространстве и повышение конечного коэффициента извлечения нефти. Traditional approaches to oil field development at late stages result in localization of a substantial portion of oil reserves in the inter-well space. Today, a number of effective technological solutions aimed at recovery of residual oil reserves in producing fields are available. One of the approaches to addressing the problem of recovery of residual oil reserves locked in poorly drained and stagnant zones provides for infill drilling. The paper presents an example of infill drilling operations conducted in carbonate reservoirs of Berket-Klyuchevskoye oil field in the Republic of Tatarstan. Various options for further development of the field using geological and reservoir simulation modeling are considered. Forecast production data due to application of proposed technological solutions aimed at enhancing oil recovery in the inter-well space and increasing the ultimate oil recovery factor are presented.

Time-lapse seismic has been providing valuable information on identifying fluid movements, to locate bypassed oil and well placement optimization to reduce uncertainties in reservoir development and production management. Most of these are made through a qualitative approach, which limits seismic data integration in reservoir simulation studies due to different scales. In order to overcome this and to develop new data integration techniques, many studies involving these processes have the assumption that both frameworks are in the same scale. Nonetheless, the quantification of lost information in the scaling procedures needs to be evaluated and quantitative seismic data integration into the simulator should improve the mitigation of these problems improving the knowledge about the representativeness of the scaled data.In this context, it is presented a technique regarding scale issues relating time-lapse seismic data and simulation models aiming to quantify the information lost due to scaling problems and how these troubles affect the history matching.This paper describes a methodology involving seismic attributes and reservoir simulation. The lost information due to scaling procedures is evaluated through comparison between flux model properties and seismic attributes, at each respective framework. This technique allows reliability improvement of reservoir parameters from seismic attributes regarding the loss of information due to scaling procedures and history matching.It has been shown that it is possible to match the history production in order to improve the process considering the scaling issues between the seismic and simulation scale, increasing model quality and reliability on results through a quantitatively analysis involving scaling procedures between 4D seismic data and reservoir simulation integrated studies.The main contributions of this technique are the integration procedures regarding scaling issues between seismic data, reservoir simulation models and history matching procedure by time-lapse seismic attributes.

Recovery factor for multi-fractured horizontal wells (MFHWs) at development spacing in tight reservoirs is closely related to the effective horizontal and vertical extents of the hydraulic fractures. Direct measurement of pressure depletion away from the existing producers can be used to estimate the extent of the hydraulic fractures. Monitoring wells equipped with downhole gauges, DFITs from multiple new wells close to an existing (parent) well, and calculation of formation pressure from drilling data are among the methods used for pressure depletion mapping.This study focuses on acquisition of pressure depletion data using multi-well diagnostic fracture injection tests (DFITs), analysis of the results using reservoir simulation, and integration of the results with production data analysis of the parent well using rate-transient analysis (RTA) and reservoir simulation. In this method, DFITs are run on all the new wells close to an existing (parent) well and the data is analyzed to estimate reservoir pressure at each DFIT location. A combination of the DFIT results provides a map of pressure depletion around the existing well, while production data analysis of the parent well provides fracture conductivity and surface area and formation permeability. Furthermore, reservoir simulation is tuned such that it can also match the pressure depletion map by adjusting the system permeability and fracture geometry of the parent well.The workflow of this study was applied to two field case from Montney formation in Western Canadian Sedimentary Basin. In Field Case 1, DFIT results from nine new wells were used to map the pressure depletion away from the toe fracture of a parent well (four wells toeing toward the parent well and five wells in the same direction as the parent). RTA and reservoir simulation are used to analyze the production data of the parent well qualitatively and quantitatively. The reservoir model is then used to match the pressure depletion map and the production data of the parent well and the outputs of the model includes hydraulic fracture half-lengths on both sides of the parent well, formation permeability, fracture surface area and fracture conductivity. In Field Case 2, the production data from an existing well and DFIT result from a new well toeing toward the existing wells were incorporated into a reservoir simulation model. The model outputs include system permeability and fracture surface area. It is recommended to try the method for more cases in a specific reservoir area to get a statistical understanding of the system permeability and fracture geometry for different completion designs.This study provides a practical and cost-effective approach for pressure depletion mapping using multi-well DFITs and the analysis of the resulting data using reservoir simulation and RTA. The study also encourages the practitioners to take every opportunity to run DFITs and gather pressure data from as many well as possible with focus on child wells.

Securing long-term energy supply for Malaysia is one of the prime responsibilities of PETRONAS; and Malaysia Petroleum Management (MPM) has been entrusted to shape the industry and enable efficient exploitation strategies and optimal development planning of Malaysian hydrocarbon assets. Production sustainability and reserve growth/addition are among the key focus area in MPM; hence, strategies and efforts are being formulated to improve the average oil field RF to more than 40%. Objective assessment of field performance, identification of recovery gaps and defining roadmap to improve field's ultimate recovery factor are critical steps to maximize the field potential ad ultimate value. This paper demonstrates the application of a hybrid workflow, comprising of data analytics-based performance benchmarking and Field Development Plan (FDP) analog assessment, to identify potential development and field management opportunities for improving economic recovery factor of an oilfield. This novel workflow consists of three key steps. First step involves reservoir performance assessment through application of diagnostic plots, decline trends and pressure/production/injection history to validate existing reserves classified as ‘No Further Activity’ (NFA). NFA reserves along with maturity assessment of undeveloped/contingent resources will provide validated recovery factor for the field. Second step is gap analysis of validated recovery factor against benchmark RF computed through data analytics carried out in Reservoir Performance Benchmarking (RPB) tool. The third and final step focusses on monetizing the RF gap and replicating best development practices through assessment of analogue reservoirs and Field Development Plans (FDPs). Analogue development cases can be from reservoirs within same field or reservoirs with similar complexity index based on RPB tool. This step involves making various cross-plots to identify opportunities like infill drilling, secondary recovery requirement, optimal producer to injector ratio, waterflood & production optimization and operational excellence. This workflow has been successfully applied to various oilfields (mature & greenfield) within Malaysia and results have been presented in this paper. The workflow has helped to identify numerous development opportunities to improve economic recovery factor e.g. new producer/injector wells, monetization plan for minor oil reservoirs, waterflood optimization and voidage management plans. These opportunities (subsurface/well/surface) are being matured for execution through MPM's enabling processes like Asset Value Framing (AVF), Asset Development Integrated Review (ADIR) and Asset Management Integrated Review (AMIR). Application of recovery factor improvement workflow coupled with reservoir benchmarking results has facilitated opportunity identification in Malaysian oilfields and defined roadmap to augment nation's oil reserves base and improve the average oil field RF to more than 40%. Using this workflow, RF gap identification in existing oilfields can be completed in relatively short period of time and actionable plans can be framed for maximizing recovery factor of the respective field.