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Collaborating Authors
SPE Asia Pacific Conference on Integrated Modelling for Asset Management
Abstract In a finite difference scheme, continuous multi-phase flow variables that appear in conservation equations such as saturation are spacially discretized on grid blocks. When coarse grid blocks are used for reservoir simulation, the numerical solution tends to magnify the discretization error. This causes numerical errors called as coarse grid effect. Through a coarse grid reservoir simulation, injection pressure showed quite difference with that of fine grid model. This is because total mobility at the injection well is defined by the finite difference based average saturation in the injection well grid block. In other words, the saturation gradient that would appear in the near-well region is ignored in such coarse-grid system. In this study, the areal average saturation in the injection well grid block was calculated analytically by the newly derived radial displacement approximation which was extende from the Buckley-Leverett linear displacement problem, taking account of pressure difference between the injection well and the injection well grid block. Consequently, the corrected total mobility was provided, by defining new value of total well index and transmissibility. The injection pressure computed by this technique with for coarse grid model is reasonably agreed with the numerical solution of fine grid model. The practical application of the developed well-pseudo is validated through an actual reservoir simulation study. Introduction The upscaling is one of the reservoir simulation techniques to reduce the number of cells in a geological model to the appropriate level for a flow simulation. The upscaling process defines a coarse grid system where each coarse grid block contains several fine grid blocks and assigns effective flow properties to each coarse grid block accounting for the flow fields simulated in a fine grid model. In near-well region, since pressure shows drastic change in radial direction, the upscaling approach for linear pressure region cannot be applied. Therefore, another approach i.e. well-pseudo which accounts for such pressure change in the near-well region is required. Historically, well-pseudo was firstly introduced to describe coning problems. In literatures, only several papers treat upscaling in the near well region. Durlofsky et al. showed an approach to calculate transmissibility and well index for single-phase flow. This method is based on the solution of local well-driven flow problems subject to generic boundary conditions. Simulation results with their method indicates improved predictions compared to those obtained by conventional techniques. However they did not take frontal advance into consideration. We developed a new well-pseudo to account for flow fields representing the near-well regions and frontal advance. A new analytical well-pseudo, it is derived by discretizing a continuous solution to Buckley-Leverett type radial displacement. The approach is an extension of Hewett et al. which analytically calculate pseudofunctions required for discretization on a coarse grid. In this paper, first, we describe the detail of the new well-pseudo. Secondly, several characteristics of coarse grid effects are revealed through calculations of well-pseudos with changing reference relative permeabilities. Finally, the practical approach of the developed well-pseudo is validated through the application to an actual reservoir model. Derivation of Analytical Well-pseudo In this section, continuous analytical solutions for single-phase and two-phase flow problems were described. Assumptions were given in radial flow system of incompressible fluid where no gravity and no capillary forces were considered. Single-Phase Property Under a single-phase radial steady-state flow condition, the pressure distribution around an injector is given by the following equation.
- Asia (0.47)
- North America > United States (0.46)
- Reservoir Description and Dynamics > Reservoir Simulation > Scaling methods (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Abstract Although application of horizontal well technology is categorized as a relatively new and expensive but it has been proven more effective and efficient in producing oil. However, the production rate strategy to obtain optimal result has not been well developed due to the difficulties to identify the influence and interaction of forces related to fluid flow mechanisms in reservoir. Particularly for oil reservoir with bottom water drive, the movement of water-oil contact/interface in a reservoir is strongly affected by interaction of the acting forces, such as: viscous force, gravity force and capillary force. The main objective of this research is to study and investigate the influence of the forces interaction on production performance of the horizontal well producing oil from bottom water drive reservoir. For this purpose, a physical scaled model has been successfully constructed to simulate the production performance. Scaling down and construction of the model are performed by using dimensional analysis. Results show that the interaction of the forces in the reservoir strongly affects the well production, in which the production performance increases as the ratio of gravity to viscous forces increases for all cases examined. Meanwhile, the changing of capillary force, which was believed by several researchers that it has no pronounced effect to the fluid flow mechanism in the reservoir, shows significant effect to the production performance of the well. The influence of reduced capillary forces in reservoir will enhance the well production performance. Consequently, in term of the ratio of gravity to capillary force, an increase in the ratio tends to improve the oil recovery. Introduction A well producing from bottom water drive reservoir, the oil production usually followed by water production. This situation occurs when bottom water has broken through the wellbore. In most cases, the use of conventional vertical well to produce oil from such reservoir always faces severe water coning condition. This is because the actual production rate highly exceeds the critical rate, defined as a rate above which the flat surface of oil-water interface starts to deform. Water coning itself is a phenomenon of bottom water intruding the oil zone such that the invaded oil zone resembles a cone. This is usually termed water cresting for horizontal well. The application of horizontal well technology has been widely used in many countries to improve oil recovery from bottom water drive reservoirs. It can be achieved since at low drawdown horizontal well can deliver a larger capacity to produce oil compared to conventional vertical well. Thus, the critical rate in a horizontal well can be higher than that in vertical well. But in practice, production rate is usually higher than the critical rate, even in horizontal well, due to economic considerations. When this takes place, high mobility bottom water will invade crestingly into the overlying oil zone and move toward to the wellbore resulting in lower displacement efficiency or oil recovery. The problem is then how to do the production strategy so that not only producing the well at considerably higher rate but also the high oil recovery can be achieved. This can be done if the fluid flow mechanism as the results of interaction of forces in the reservoir is fully understood. During well production, three different forces work in the reservoir; they are viscous force, gravity force and capillary force. Complex mechanism of fluids flow in a reservoir system containing a horizontal well and in the wellbore itself are not well understood yet. Tackling such problem, several researchers therefore simulated into the physical model. Most of the researchers used the well-known Hele-Shaw model similar to the one employed by Meyer and Searcy studying water coning behavior for vertical well. Consequently of using this model is that the role of capillary pressure in the system cannot be studied since the gap between the plates so wide that the capillary force is negligible. The objective of this research is therefore to study and investigate the influence of the forces interaction on production performance of the horizontal well. To meet this objective, the physical model using consolidated sandpack was developed.
- Asia (0.94)
- North America > United States > Texas (0.46)
- Europe > Netherlands > North Sea > Dutch Sector > Q01a-Ondiep License > Haven Field > Vlieland Sandstone Formation (0.99)
- Europe > Netherlands > North Sea > Dutch Sector > Q01B-Ondiep License > Haven Field > Vlieland Sandstone Formation (0.99)
Abstract Recent years have seen a growing trend towards applying new and advanced technology in the Russian oil and gas business to maximize productivity and enhance assets value. This has led to improved efficiency and greater technical challenges. In large measure, Sibneft owes its predominant position as one of the rapidly growing oil producers in the Russian energy business to its willingness to embrace new technology in order to enhance the value and maximize the productivity of its assets. This paradigm shift has been critical to the company, not only to maintain its leadership among the majors in Russia, but also to be consistent with the country's aggressive strategy to enhance production rapidly to meet local and international energy demand. This paper focuses on how Sibneft management has been keeping abreast of new technology in order to meet these technical challenges. Romanovskoe oilfield, which is located in the Western Siberian region, is one such field that has been subjected to this proactive philosophy. Due to the heterogeneous characteristics of the reservoir, inefficient thin beds and relative low permeability, specific applications or "right sizing" of technology are crucial to ensure effective exploitation of the field potential. All the wells in the field are either producing via horizontal wells or have been fracture-stimulated since the beginning of their production history. The critical success factors that emerged from the applications are accurate well placement within the thin oil column (landing the well in the right place and at the right angle), avoiding poor quality reservoir and undulating wellbore for the horizontal wells, and fracture-stimulating the wells in the low productivity regions. The adoption of the strategy has seen substantial increase in the field total production, which is otherwise difficult to achieve without appropriate applications of specific technology. The successes on overall enhance the long-term value of the asset. Introduction For the past several years, there has been a growing trend towards applying new and advanced technology in the Russian oil and gas industry. The main reason for this growing trend has been the increasing awareness of the Russian energy business about the critical need to improve production efficiency and maximize reservoir productivity. This is further catalyzed by the country's aggressive strategy to enhance production to meet the local and international energy demand. Among the major operators in the country, Sibneft has been the frontrunner in embracing this paradigm shift, and has been instrumental in proactively putting the idea into action. The purpose of this paper is not to discuss the philosophy and vision adopted by Sibneft concerning the application of new and advanced technology in detail, but rather to focus on how the company has been adopting and applying certain technologies, namely hydraulic fracturing and horizontal wells, and judiciously utilizing them in order to develop its assets. The underlying philosophy is fundamentally simple, but practical; selecting "fit-for-purpose" solutions, and then "right-sizing" them according to the needs, depending on the nature and characteristics of the reservoirs. The Romanovskoe field, which is located in the Western Siberian region, has been selected as a case example to show the company's experience in leveraging these technologies. The field is one good example to reflect the characteristics of many assets in the Western Siberian region, inefficient thin beds with relatively low permeability, and widespread structural and geological heterogeneities with underlying water bearing zone in close proximity. Due to these heterogeneous characteristics, efficient development of the field to enhance productivity and maximize recovery is a challenge that requires careful selection and application of technology. The paper begins with a fundamental review of the Romanovskoe oilfield structure and geology. This provides understanding of the reservoir and formation heterogeneity, and some critical insights of the technical challenges associated with the development of the field. The key technology applications focus on hydraulic fracturing (for the vertical wells) and horizontal wells. Several well case histories are provided to demonstrate the applicability of the technology employed, including the analysis of the wells and the field production performance to evaluate the overall success of the endeavors in enhancing the value of the asset.
- North America > United States > Texas (1.00)
- Europe (1.00)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (35 more...)
Abstract The paper describes results of a petrophysical study aimed to improve reservoir description of a complex oil reservoir located in Western-Siberia, Russia. The K-field was put on production in 1998. The reservoir rocks were deposited in a sand-rich deltaic environment, that implies reasonably good lateral sand bodies continuity. Additionally, no evident continuous faults were seen by 3D seismic survey. However, recent field development has revealed far more complex reservoir compartmentalization and heterogeneity, than it was supposed at the exploration stage. A considerable variation of oil-water contact was encountered and large discrepancy was observed between log predicted and observed well productivity. Additionally core experiments demonstrated poor correlation between porosity and permeability with two orders of magnitude permeability variation at similar porosity values. The hydraulic flow unit (HFU) approach is used in the present study as an integrating tool for petrophysical description of the reservoir. First, we start from a rock type classification based on core data to pick out major HFU constituting the reservoir. We employ combination of routine and special core analysis data to work out a resulting rock type classification for the studied field. Along with description of the HFU classification, we present the underlying geological reasons which control FZI variation for K-field reservoir. Based on geological and physical background we select relevant logs types related to FZI and propose simple regression approach of for prediction of FZI using gamma-ray and effective porosity log readings. Predictive capabilities of proposed regression approach is compared with more complex statistical techniques and we show that regression approach have reasonable accuracy of predicted FZI comparable to Bayesian inference and artificial neural network methods. Then we use HFU distributions obtained for each logged well along with classified capillary pressure data for calculation of synthetic water saturation logs and estimation of the free water level (FWL) depth. The estimated FWL data supplemented with seismic information about possible discontinuities and faulting zones are used to update reservoir compartmentalization scheme and to delineate pay zones. The 3D spatial distribution of the HFU is obtained using geostatistical modeling techniques and integrated into the geological reservoir model to define the porosity-permeability relationships. Additionally, HFU are used in the dynamic reservoir model to assign regions of relative permeability and capillary pressure functions. The above described simple engineering application of the hydraulic flow units approach allowed us to construct an improved reservoir model and delineate a new probable pay zones, what lead to an increase of estimated oil in place by 70 %. Introduction The HFU approach is a methodology for classification of rock types and prediction of flow properties, based on sensible geological parameters and the physics of flow at pore scale. The theory of the method was originally suggested by Amaefule et al [1] and further developed by other researchers [2]. Development and application of the HFU approach is stimulated by the common problem of permeability prediction in uncored but logged wells. Classical approaches for estimation of permeability are based either on simple logarithmic regressions evaluating permeability from log-derived porosity (Eq. 1) or on empirical correlations which relate permeability to various log responses.Equation 1 Both traditional approaches are empirical and have no or little physical and geological background. The regression methods deliberately ignore experimental data scatter and predict smoothed permeability distributions, which usually do not reproduce observed variability of permeability. The other empirical correlations based on various log responses usually have limited local applicability since, they were derived for particular geological settings.
- Research Report > Experimental Study (0.34)
- Research Report > New Finding (0.34)
- Geology > Mineral > Silicate (0.75)
- Geology > Sedimentary Geology > Depositional Environment > Transitional Environment > Deltaic Environment (0.54)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.47)
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
Abstract The proposed revitalization of the Bokor field is affected by many surface-facility constraints as well as the subsurface complexity of laminated stacked reservoirs. Such complex problems require a truly integrated multidisciplinary methodology using a decision-and-risk-assessment approach to screen development options. This paper presents the process adopted and used to screen and rank the various options. Any field redevelopment needs to begin with an identification of system bottlenecks and proposals to remove them, but often this is only considered at a facilities level. In proposing a revitalization plan for the Bokor field, the joint Petronas Carigali Sdn. Bhd (PCSB)-Schlumberger team had to develop a complex decision-making process to select an optimal development plan that would solve the constraints while minimizing unit technical operating cost (UTOC) and maximizing production. Often, brownfield redevelopments are limited to maximizing existing facilities (slots, processing plant). However, in the case of Bokor, essentially no additional oil can be produced without an impact on existing production (lack of gas lift, lack of export compression). Thus, an approach was required that not only solved the existing bottlenecks but also allowed for sufficient additional capacity to sustain a cost-effective revitalization plan. The process had to be iterative, assessing the risks and uncertainties of each approach and its economic impact. The solution was an approach that considered each reservoir target by discounted cumulative oil, thus producing a ranked list of opportunities that could be added together to form any development scenario. Hence, rather than running a reservoir simulation on each development case, this approach allowed multiple facility development options to be tried quickly. Each development scenario was then analysed using a tornado diagram. From this diagram was prepared a decision tree that gave the most likely outcome. This approach allowed options as diverse as subsea tiebacks to full integrated platforms with a high number of electrical submersible pumps (ESPs) to be risked and ranked equitably within a reasonable timeframe. Introduction Field optimization in brown field environments, in particular, is an area where subsurface engineering, production technology, and drilling and facility engineering disciplines frequently conflict in selecting the most technically appropriate field redevelopment strategies and plans, despite the apparently aligned interests in maximizing and optimizing reservoir drainage. The conflict arises because of the constraints imposed by any existing infrastructure, such as existing location versus new well target locations, existing facilities capacity versus new required capacity or existing infrastructure mechanical integrity, relative to a green field development where no such predetermined constraints exist. Consequently, the most effective and economic solutions may not be easy to establish without the use of a powerful holistic modelling approach. In addition, the paradigms of deterministic and probabilistic thinking, prevalent to varying degrees within these various disciplines, introduce a further dynamic that lends itself to resolution or conciliation through the use of an integration process and tool.
- North America > United States > Texas (1.00)
- Asia > Malaysia > Sarawak > South China Sea (1.00)
- Asia > Malaysia > Sarawak > South China Sea > Sarawak Basin > Baram Delta Province > Bokor Field (0.99)
- Asia > Malaysia > Sarawak > South China Sea > Sarawak Basin > Baram Delta Province > Block SK307 > Betty Field (0.99)
- Asia > Malaysia > Sarawak > South China Sea > Sarawak Basin > Baram Delta Province > Block SK307 > Baronia Field (0.99)
Abstract The paper introduces oil production engineering series for heterogeneous, multilayer sandstone oilfield in the basis of separate zone production in the four development phases including production and stable production. The technologies provide technical means for realizing "Three-changes" of oilfield development, make an important contribution for keeping stable production of 50 million tons for 27 years in heterogeneous, multilayer sandstone oilfield. The development process and several technologies for different development phase are introduced in the paper. Introduction Daqing Oilfield is the largest oilfield in China. It is a giant, nonmarine, heterogeneous and multilayer sandstone oilfield whose reservoirs can be divided into 80–120 small layers. The reservoirs' total thickness ranges from 100 to 150m, and for single layers, the thickness is 0.2 to 30m. The maximum permeability is 1.2μm while the minimum is 0.004–0.005 μm, which makes the interval permeability contract between layers up to 60 times. After 42 years' development, a set of development theories and technologies have been created for the giant, nonmarine, heterogeneous and mulitilayer sandstone oilfield. Till the end of 2002, the field-wide recovery factor was 47.2%, and in La-Sa-Xing reservoirs, some of the main reservoirs in Daqing, occupied up to 50.4%. And it has been 27 years that Daqing oilfield produced oil stably above 50 million tons (see Fig1.). From the initial increasing the production process to the later stabilizing production process, separate zone injection development theory has been created for resevior enginerring, as well as the separate zone oil production technologes for oil production engineering. In general, there are three changes in the process of Daqing Oilfield development:The change of development objective from main reservoir to medium-low permeability layer and untabulated layers which are thin and poor. The change of production method from natural flow production to full-scale artificial lift production. The change of driving method from single waterflooding to the co-existance of waterflooding and polymer flooding step by step. After the above treatments, Daqing Oilfield's yearly production reached 5,030×10tons in 1976 (Daqing Oilfield was found in 1959 and put into prodnction in 1960), and entered into a stable phase of yearly oil production above 5,000×10tons. From 1994, the yearly production reached a four-year peak of 5,601×10tons. In 1996, the oilfield entered into the full-scale development phase. All the development methods came into effect including water flooding, polymer flooding and developing peripheral low permeability reservoirs which contributed to keep a stable production of 5,000×10 tons till 2002.
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
- North America > United States > Louisiana > China Field (0.97)
Abstract Uncertainty resolution in recovery driving factors is a crucial issue in oil and gas exploration and exploitation activities. One such application is to select field candidates for development in the midst of several stochastic variables e.g. recoverable reserves, production rates, gas/oil price, discount rates etc. Unfortunately, the cashflows from investments tend to be stretched out in several years. Traditionally, to measure such inherent potential risks, engineering analysis is performed along with project economics. Engineering analysis builds confidence around recovery factors whereas the economic analysis justifies the returns through NPV and IRR computation. One implicit yet critical behavior, however, is often neglected. Investments tend to have embedded flexibilities, i.e. they are not always now or never type, which can be valued as flexible decisions via the theories available for financial options mathematics. This paper investigates the application of financial mathematics to determine viability of a tight gas reservoir as an investment candidate and presents some interesting results dictated by intrinsic optionality. Real options (RO) have gained increasing popularity in the oil and gas community in the recent past. These applications employ analytic solutions of Black-Scholes type partial differential equation (PDE) available in the literature which are usually limited to cases of relatively simple payoff structure, exercise strategy, lower dimensions etc. However, most realistic cases, at the very least, will have complex payoff structure e.g. cascading cashflows in the example considered in this paper. Moreover, these options can be exercised anytime during the life of the project i.e. American type options. To accurately and rigorously compute option values in such cases one has to resort to suitable numerical approach to solve the PDE along with appropriate, complex boundary conditions. In this paper, we prescribe one such technique, namely Implicit Mulitgrid Finite Difference (IMFD) to asses a two well pilot development program. Based on a previous engineering study, stochastic driving factors for the investment are determined. The investment is then crafted in a RO framework. Representative PDE is solved with imposed boundary conditions. Two different scenarios are considered and results discussed. Finally, exercise boundaries are forecasted above which, at a given time in the course of the project life, it is beneficial to exercise the option (in this example drill the development well) instead of waiting for a future exercise. Background and Motivation Traditional Discounted Cashflow (DCF) approach suffers from one significant drawback, namely it assumes single decision pathway with fixed outcomes. On the other hand, in practicality decisions are actuated in the midst of uncertainty resolution and knowledge gained by management. This consequence of high uncertainty coupled with management's flexibility to make midcourse strategy corrections as more information is made available is the essence captured in the real options approach. Management always acts rationally and with judgment whereas DCF based economic valuation methodology never accounts for this way of action. Occasionally, DCF results are further refined by scenario analysis, Tornado diagrams and Monte Carlo simulations of sensitive variables. Nevertheless, none can capture the value of flexibility and knowledge. This additional knowledge gained ultimately resolves uncertainty around key variables which, in turn aids rational decision making. This age old, inherent disconnect between theory and practice has motivated researchers to borrow ideas from financial options and reconstruct a new framework to value projects through real options12. Although slow to gain widespread popularity, the prevalent literature suggests that there are numerous business instances where real options can deduce a much higher value compared to static NPV calculations. It must be mentioned, however, that the projects which are deep-in-the-money (positive NPV) or deep-out-of-the-money (highly negative NPV) are easier to decide on and should never be considered for further real options analysis. It is the near-money (swing) projects that could benefit from the insights gained from real options analysis.
The Use of Integrated Simulation in Decision-making for the Development of Qiaokou Oil-rim Gas Condensate Field
Guo, Xiao (Southwest Petroleum Inst.) | Du, Zhimin (Southwest Petroleum Inst.) | Jiang, Yiwei (Zhongyuan Oilfield) | Sun, Lei (Southwest Petroleum Inst.) | Bi, Jianxia (Zhongyuan Oilfield) | Liu, Xueli (Southwest Petroleum Inst.)
Abstract The development of complex, deep gas condensate fields with oil ring was once a difficult and uneconomical task to perform. The optimization of conceptual design has now become cost efficient through the use of integrated simulation. This presentation focuses on the integrated study of Qiaokou oil-rim gas condensate field, located in Zhongyuan oil field. The reservoir is of low permeability, low porosity, deep pay and has three fault-isolated produced zones, named Qiao14, Qiao69 and Qiao58 blocks. In 2002, 28 infills were drilled on the basis of adding incremental reservoirs. With the advent of widely available high-accuracy reservoir predicting technology, under-balanced drilling technology and large-scale fracturing technology in Zhongyuan oil field, encouraging factors and results led to a desire to further field-scale development plans. An detailed integrated study of Qiaokou oil-rim gas condensate reservoirs was proposed. This study involved building a highly detailed earth model to accurately define the geologic framework, and a scaled-up simulation model to optimize the field demonstration project. Based on well log, geologic, and core data, individual-layer data and the faulted structure were mapped. Reservoir behavior of oil-rim gas condensate reservoir is modeled using a 3-D reservoir simulator. The model incorporates a description of the phase behavior of gas and oil rim, well stimulation and compaction in the reservoirs. The multi-disciplinary demonstration of reservoir evaluation, gas engineering, PVT analysis, numerical simulation, gas production practice, fracture acidizing on Qiaokou oil-rim gas condensate reservoirs has been accomplished by earth scientists, field engineers, and reservoir engineers. An integrated simulation incorporating the demonstrated results of these engineers has been presented to make decisions in Qiaokou oil-rim gas condensate field development. The study showed the integrated numerical modeling of Qiaokou oil-rim gas condensate reservoirs can be cost effective and SINOPEC has already ratified the further development plan in light of the results of this study. Our conclusions and recommendations will help improve future management and development of Qiaokou oil-rim gas condensate field. Introduction For the past 20 years, the multidisciplinary approach of closely related teamwork across the disciplines of geology, geophysics, petrophysics, reservoir engineering, drilling and production engineering has gained acceptance as a management process dealing with the life cycle of petroleum reservoir starting from discovery to abandonment and all the stages of growth in between. The traditional rule that each phase of work, under the reservoir life process, was undertaken by a group of people under a manager trained only in that discipline, has been replaced by ‘team work’ which introduces integration of multi-disciplines in a decision making process. Fig. 1 shows components of integrated reservoir characterization and the contribution of each discipline to the process. Nowadays, integrated reservoir management has been an increasing interest in the petroleum industry. Especially, it has played an important role in the development of complex oil and gas reservoir.
- Asia > China > Henan Province (0.55)
- North America > United States > Texas (0.46)
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Asia > China > Henan > North China Basin > Zhongyuan Field (0.99)
- Africa > Middle East > Egypt > Western Desert > Bahariya Formation (0.99)
Abstract An integrated reservoir study represents the one reservoir modeling technique available to a reservoir management team that incorporates ALL of the information available regarding a petroleum reservoir. As such, the integrated study has the potential to provide the team with the highest resolution most accurate description of their field that is currently available. However, that high resolution comes at the expense of a highly complex, data intensive process. This paper was an attempt to simplify and codify the complex process of performing an integrated reservoir study. The paper presents an overview of the integrated reservoir modeling process including how that process has changed from the early days of reservoir simulation to the present day. Two models are presented that illustrate the study process for a 1980 time frame multi reservoir study and a 2002 time frame geostatistically based compositional reservoir model. Emphasis is placed on the changes in workflows from the early models — simple mapping of properties and manual digitization of maps to simulation model grids — to the more complex models of today — with property distributions based on object modeling and geostatistical analysis to distribute reservoir properties. Through the examples, the paper illustrates the point that reservoir studies have evolved from a time when the geologists and engineers often knew more about their reservoirs than the available modeling tools would allow them to implement in their models - dual porosity and flow across faults, for example - to the point where today we often have the modeling capability to model more complex phenomena than our knowledge of the reservoir may warrant - for example, object modeling with no data on the characteristics of lithofacies in our reservoir, or dual porosity flow models with no data on fracture spacing and distribution. The Integrated Study Conceptually Although the term "Integrated Study" only gained widespread use in the 1990's , the conceptual tasks needed to build a model of a reservoir have been identified and performed since the advent of multi-well full field simulation studies. Those tasks — structural interpretation, petrophysical analysis, stratigraphic analysis, fluid PVT analysis, and reservoir simulation - have formed the basis for building models since the 1970's and continue today to be the backbone of the "Integrated Study" concept. What has changed in the Integrated Study concept is:The switch from the analog to digital form for the data input and analysis results of the "geo-science" tasks of the studies The development of ever more mechanistically sophisticated analysis tools, for exampleObject modeling in facies identification work Geostatistical methods in distributing petrophysical properties inter-well, Arbitrary connections in simulators to allow modeling of faults and fractures Many orders of magnitude faster computers and greater data storage capacity As a result of the sophisticated tools and greater computing capacity, the focal point of all of the model building process has moved from the reservoir simulation "dynamic" model in the integrated study concept of the 1980's, Figure 1, to the geologic "static" model today. This movement of the focal point is, we believe, a major reason for the greater interaction between the disciplines and tasks that is the emphasis of the 2003 integrated study concept, Figure 2.
- North America > United States > Texas (0.93)
- Europe (0.68)
- Geology > Structural Geology > Fault (1.00)
- Geology > Rock Type (1.00)
- Geology > Geological Subdiscipline > Stratigraphy (1.00)
- Geology > Sedimentary Geology > Depositional Environment (0.94)
- Geophysics > Seismic Surveying > Seismic Interpretation (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Faults and fracture characterization (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
Abstract Reservoir heterogeneity, along with the oil to water viscosity ratio, cause fingering and water breakthrough along fractures or higher permeability layers of in water flooding oilfield. This in turn decreases the water sweeping volume and water drive effect, making the medium or lower permeability layers poorly productive or even unproductive. As a result, the production wells will be flooded before due or will have a rapidly increased water-cut. Blocking higher permeable layers with chemical reagents along the flow direction of water can efficiently increase the water-affected volume; adjust productive and absorptive sections of the reservoir. Therefore, the water-cut can be decreased, the oil production can be increased, and the objective of stable oil production and lower water-cut can be achieved. This paper presents the techniques used in a field test project conducted at Daqing Oilfield. Granular gel-polymer was used as blocking agent. Economically improved oil production and reduced water-cut were observed. Introduction According to the geological characteristics and the behavior of reservoirs in north Xingshugang region of Daqing Oilfield, both domestic treatment agents and alien agents were investigated. The physical and chemical capability of agents were also compared and analyzed. In the end, the granular gel-polymer was chosen as the treatment agent. This kind of granular gel-polymer was formed through a cross-linking system on ground. First of all, gel was formed. Then, the gel was made into particles, dried, smashed, and griddled into gel granules. The gel granules, which exist as dispersed spherical particles in water, have certain characteristic of volume inflation. After being injected into the porous pay zones, the gel granules are deformed and moved towards the producing wells. In formations that are far from the injection wells, the gel particles become stagnant inside the porous and choke the channels of the porous because of the small pressure difference. The stagnancy and choke will convert the flows of injected water. This technique has a very good effect as to solving the defects in the underground cross-linking system such as the difficulties of controlling the formation of gel, the strict range of usage, and the complexities of operational techniques. The granular gel-polymer has undergone laboratory test and has the following of characteristics:Granule diameter: There are three kinds of diameters granules. They are 1.5mm, 3mm, and 5mm respectively. Expansionary multiples: The expansionary multiples are 60~80 times when the granules are combined with injecting water used in Xingshugang region. Expansionary velocity: The expansion velocity is controlled at 30~60min under the temperature of 45°C. Brine tolerance: The granules are not influenced by salinity. Stability: It will neither dehydrate nor gelout within two years under room simulated filed conditions. The well to be treated is X7–2-F24, which is located in north Xingshugang region in Daqing Oilfield. This well was put into injection in November 1992 and had injected 85.0036×10m of water before treatment. There are four production wells around this well as shown in figure 1. They are X 7–1–25, X7–2–23, X7–2–25, X7–2–27, and X7–3–28. All these wells constitute a well group, by which we called X7–2-F24 well group. Figure 2 illustrates the result of voltage logging of X7–2-F24. The injected water mainly flew toward two directions.
- South America > Venezuela > Lake Maracaibo > Maracaibo Basin > Ayacucho Blocks > Motatan Field (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)