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Results
Novel Waterflooding Strategy By Manipulation Of Injection Brine Composition.
Ligthelm, Dick Jacob (Shell Intl. E&P BV) | Gronsveld, Jan (Shell Intl. E&P BV) | Hofman, Jan (Shell Intl. E&P BV) | Brussee, Niels (Shell Intl. E&P BV) | Marcelis, Fons (Shell International Exploration and Production B.V.) | van der Linde, Hilbert (Shell Intl. E&P BV)
Abstract As brine composition profoundly influences reservoir wettability and hence microscopic sweep, careful design of injection brine is part of a strategy to improve on oil production in existing and future water flooding projects, in both sandstone and carbonate reservoirs and in combination with follow-up EOR projects. The following results were found:Formation water with higher salinity level correlates to a higher content of multivalent cations. This causes the (sandstone) reservoir wettability to be more oilwet; The field-observed temporary reduction in watercut during breakthrough of so-called "Designer Waterflood" water in a Middle Eastern sandstone reservoir with highly saline formation water was interpreted to be caused by an oil bank ahead of the slug of injected water; The oil bank results from improved sweep by wettability modification to more waterwet state. The interpretation was confirmed by laboratory experiments; Experiments in limestone core plugs demonstrate similar wettability modification, if the sulphate ion content in the invading brine is far in excess of the calcium ion content. Based on these results the following conclusions were drawn:Designer Waterflooding may increase the Ultimate Recovery of oil by at least a few percent; There is scope for further improvement in oil production by flood front stabilization by adding low concentration polymer to the optimised slug; If future EOR projects are planned, a Designer Waterflooding pre-flush is recommended to obtain more favourable oil desaturation profiles and savings on polymer costs; In case of seawater injection into reservoirs with formation water of low salinity level, removal of multivalent cations from the seawater should be considered to avoid the potential risk that the reservoir becomes more oilwet, which will result in reduced sweep. Introduction In the past decade, injection of brines with well-selected ionic composition in sandstone and carbonate reservoirs has been developed into an emerging IOR technology, aiming for improved microscopic sweep efficiency with reduction in remaining oil saturation as result (Tang and Morrow, 1997, 1999, 2002; Maas et al, 2001; Webb et al, 2003 and McGuire et al, 2005). Recently, some evidence of the beneficial impact of injection of brines with well-selected ionic composition from historical field data was published (Robertson, 2007). In-house research on this subject covered a broad range of disciplines, including core flow and Amott imbibition experiments, Colloid Chemistry and Petroleum Engineering. In this paper we describe the major results from our study and indicate where this technology can be most favourably applied.
- North America > United States (1.00)
- Europe (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Mineral (1.00)
Abstract During the primary production of fractured reservoir most of oil is produced from fractures and a lot of oil remains in matrix. Trapped oil in the matrix can be recovered by gas injection by activating gravity drainage mechanism. In addition there is a big impact of molecular diffusion of oil and gas in total oil recovery from fractured reservoir. The experimental work can by used to model this mechanism in combination of numerical simulator to investigate this phenomenon more accurately. A fully compositional model has been applied to a numerical experiment in literature to investigate the drainage of CO2 from a core with artificial fractures and the effect of molecular diffusion included. The same study has been applied for a synthetic fractured reservoir model to investigate the effect of CO2 injection in oil recovery mechanism in the field scale. In this work we found that at early stage we have oil swelling and gravity drainage followed by a slow extraction mechanism which recovers the intermediate and heavy components from the residual oil. The combined effect of diffusion and gravity suggests that application of the oil and gas diffusion coefficients is critical in any field scale simulation of a fractured reservoir and the correct diffusion coefficients should be applied. A lot of oil reservoirs in the world are fractured and with primary recovery we can produce maximum 30 % of original oil in place therefore we need to have an accurate observation of secondary and tertiary oil recovery in these reservoirs. The understanding of oil recovery mechanism also is crucial for reservoir management especially when developing field management plans. A low miscibility-pressure requirement often is a significant advantage of CO2-miscible flooding. This process could have significant future application in areas with economical CO2 supplies from natural deposits or surface sources. Introduction A lot of oil remains in matrix blocks in fractured reservoir after primary recovery of reservoir. For recovering substantial quantities of that oil trapped in the matrix block gas injection is one method which will activate the gravity drainage mechanism in reservoir. The density difference between gas in the fracture and oil in the matrix causes production of oil until gravitational forces are equalized by capillary forces. However, in many cases like low permeability of matrix, small size matrix blocks and high capillary pressure, gravity drainage may be very low or ineffective but still one solution to recover matrix oil is to inject a dry gas. Thus, mass transfer takes place between the gas in the fracture and the gas/oil system saturating the matrix blocks. The theory of fluid flow in fractured porous media developed in the 1960's by Barrenblatt et al., (1960). Warren and Root (1963) introduced the concept of dual-porosity models into petroleum reservoir engineering. Since that time, numerical modeling of naturally fractured reservoirs using dual-porosity models has been the subject of numerous investigations. However it's difficult to present imbibition and gravity drainage properly in the dual-porosity and dual-permeability formulations most commonly used in industry to model fractured systems. In some formulations, attempts have been made to represent correctly the physical behavior of process by considering a gravity term, and assuming a simplified fluid distribution in the matrix blocks. Using a gas phase for improving oil recovery in the fractured reservoirs, one of these phenomena creates in the system: 1- first contact miscibility, 2- vaporization mechanism, 3- condensation mechanism or 4- condensation/vaporization mechanism.
- Europe (1.00)
- North America > United States (0.93)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- (2 more...)
Abstract An accurate knowledge of the initial state of a petroleum reservoir is crucial in order to optimize its development plan. Such knowledge relies on a correct description of the spatial distribution of the fluid components. The compositional variations are mainly due to gravitational segregation and thermo-diffusion phenomena. Usually, a good estimation of the steady state spatial distribution of the components is obtained by thermodynamic modeling based on an Equation of State (EoS). This heuristic approach is unable to yield any knowledge on the time required to establish a segregated profile and it needs correlation for the thermodiffusion coefficients which is not readily available. One way to provide further information, both on the dynamic of the segregation and on the thermodiffusion process is to use Molecular Dynamics (MD) simulations. In this paper, Both EoS and MD simulations were applied for the calculation of the fluid distribution in reservoirs. MD results provide insights on time evolution/stability of the fluid distribution and the calculated profile were used to tune the parameters of the EoS model for current applications. On systems, for which an analytical solution of the thermo-gravitational problem exists, it is shown that the molecular simulations results are consistent with expected profiles. The MD simulations confirmed a non negligible impact of thermodiffusion phenomenae on the concentration profiles. In addition, simulations have shown that the transient behavior of both isothermal and non-isothermal segregation follows a diffusion process dynamic based on the mutual diffusion coefficient. Comparison of MD results and EOS based model were made for various systems to evidence the limitation and the relevance of the thermodynamic approach. Gravity segregation calculations are widely used for the reservoir fluid evaluation and for the initialization of the reservoir model. This paper gives an in depth investigation of the underlying physics and direct validation of EoS modeling through molecular simulations. Introduction An accurate knowledge of the initial state of a petroleum reservoir is crucial in order to optimize its development plan. This relies on the ability of describing correctly the spatial distribution of the fluid components. The compositional variations, when the fluid column is not subjected to a global convection, are mainly due to gravitational segregation (Høier and Whitson 2001; Montel et al. 2007) and to a less extent to thermodiffusion phenomena induced by the geothermal gradient (Ghorayeb et al. 2003; Montel et al. 2007). Usually, a good estimation of the convection free steady state spatial distribution of the components is obtained by thermodynamic modeling based on an Equation of State (EoS) (Halldórsson and Stenby 2000). Nevertheless, this heuristic approach is unable to yield the time required to establish a segregated profile nor to provide any direct information on the stability of the fluid column. In addition, apart from the intrinsic limitation of the EoS, such an approach needs an ad hoc correlation to take into account thermodiffusion which is not readily available for all mixtures despite recent improvements for some kind of mixtures (Artola et al. 2008; Kempers 2001; Shukla and Firoozabadi 1998; Wiegand 2004). In many reservoirs, the compositional gradients are different from the calculated one assuming stationary state. The deviations are generally explained by the slowness of the diffusion process, leading to a "partial" segregation situation. But the gravitational segregation process is quite different from any usual diffusion processes where the components diffuse through a boundary. All components at any depth are submitted to the gravitational force.
Abstract A benchmark for computational integration of petroleum operations has been constructed. The benchmark consists of two gas-condensate reservoirs producing to a common process facility. A fraction of the processed gas is distributed between the two reservoirs for gas injection. Total project economics are calculated from the produced streams and process related costs. This benchmark may be used to compare different computational integration frameworks, and optimization strategies. The methods of model integration and optimization discussed in this paper are applicable to complex petroleum operations where it is difficult to quantify cause-and-effect without comprehensive model-based integration. A framework for integration of models describing petroleum operations has been developed. An example test problem is described and studied in detail. Substantial gains in full-field development may be achieved by optimizing over the entire production system. All models and data in the benchmark problem are made available so that different software platforms can study the effects of alternative integration methods and optimization solver strategy. The project itself can, and probably should, be extended by others to add more complexity (realism) to the reservoir, process, and economics modeling. Introduction The petroleum industry has developed advanced modeling tools and applications for describing the key segments of upstream-to-downstream projects - reservoir simulators, network pipeline simulators, compressor models, surface product process simulators, and economic applications. The custodians of these models are specialists and often know little about the complexities of models used by other disciplines. Historically, educational institutions and most industry discipline structures (Reservoir, Production, Drilling, Transportation, Process, Financial) lead to segregation of people. In recent years, integrated operations has led to improved localization and communication amongst discipline groups in large petroleum projects. Control room technology, high-speed communication, and some physical changes in localization into project vs discipline housing has moved the industry towards better integration. Despite the improved integration of people and communication, less progress has been seen with integration of the models themselves. Today's practice involves using models independently, often with clumsy and time-consuming hand-shaking interfaces that are adhoc file transfers from one modeling group to another. More automated integration software solutions tend to work smoothly with applications from a particular vendor, but don't provide an "ecumenical" interfacing capability for any application. With a truly integrated model, one can optimize (for example) project net present value by changing controllable variables such as gas injection rate and composition, process unit conditions, pipeline size, etc., subject to constraints such as number of wells, sales gas heating value and CO2 content, etc. Optimization can involve rigorous multi-variable maximization, or it can simply provide quantitative cause-and-effect assessment. Several interesting papers have dealt with model-based integration and optimization (Bailey et al. 2005; Cullick et al. 2003). These authors discuss complex petroleum projects with emphasis on uncertainty analysis within an optimized and integrated modeling environment. Unfortunately those papers, and similar ones by the same authors, are not ameanable to creating an open benchmark, as is our intention here. Also, these authors do not deal with compositional issues and surface processing as done in the project presented here. This paper provides a benchmark for an integrated petroleum project that uses several models to integrate streams from reservoir to market value. This project provides a starting point for discussion and comparative solutions to a simple-yet-realistic integrated petroleum project. Hopefully the benchmark will provide a platform for comparison of model integration software and optimization methods developed by academia and industry.
Real Time Integration of Reservoir Modeling and Formation Testing
Gisolf, Adriaan (Schlumberger Oilfield Services) | Dubost, Francois Xavier (Schlumberger) | Zuo, Julian Youxiang (Schlumberger) | Williams, Stephen M. (StatoilHydro) | Kristoffersen, Julianne (Schlumberger) | Achourov, Vladislav V. (Schlumberger) | Bisarah, Andrawiss (Schlumberger) | Mullins, Oliver C. (Schlumberger)
Abstract The increasing complexities of newly discovered reservoirs coupled with the increasing cost structure of field development mandate significantly improved and timely work flows for reservoir evaluation. Traditional modeling workflows are typically time consuming and require well organized cross disciplinary integration between geoscientists. Such models and processes are not well suited to be used and updated during formation evaluation acquisition phases of field development. In this paper a more accessible approach is proposed and demonstrated. The existing fluids model is combined with the current geologic model to construct an accurate representation of key features of the reservoir. This model is then used to predict data for a wireline formation sampling and testing tool (WFT), with emphasis on downhole fluid analysis (DFA). In this process, current reservoir understanding is tested by direct measurement in real time. If differences are uncovered between predicted and measured log data, the WFT tool is in the well, and measurements can be made to uncover the source of the error. In this paper a workflow is demonstrated where WFT DFA and PVT lab reports were used to build a fluid model after the first exploration well data was acquired. This model was then used to predict fluid properties and WFT DFA logs for a subsequent well intersecting nominally the same compartment. These DFA predictions presumed fluid equilibrium and flow connectivity. Real-time comparisons were made of predicted and measured pressures, fluid gradients, contacts and DFA data obtained from the WFT logging run. Agreement of predicted and measured log data indicates that fluid properties and reservoir connectivities used for the modeling are correct. If predictions disagree with measurements the acquisition program can be altered in real time to ensure sufficient data is acquired to understand the reservoir model inaccuracies. During the WFT logging job, this predictive model enabled validation of critical WFT data. This process also allowed testing of the reservoir connectivity. It was discovered that either compartmentalization or lateral disequilibrium of the fluids in the reservoir exists. Interpretation of the DFA data suggested that a subtle lateral disequilibrium exists and the assumption of reservoir connectivity is supported. Introduction As the search for hydrocarbons goes deeper and into more challenging reservoirs, greater reservoir complexity must be addressed. To properly evaluate such reservoirs continuously challenges formation evaluation technology and techniques as well as economic limitations. It is essential to improve efficiency in this evolving setting. The existing work flows in reservoir evaluation offer opportunities for improvement. One area of potential improvement is identification of compartmentalization.[1–4] The extent of reservoir compartmentalization has a direct impact on the number of wells and the geometry and completion of those wells required to drain a reservoir, thereby greatly affecting the cost structure. Compartmentalization is very difficult to determine. Compartmentalization is best analyzed by history matching production over many years.[5] However, this approach is simply not practical in most new oil fields because in higher cost markets, huge capex must be expended prior to first oil. Well testing is also useful when identifying compartments, however, the large cost of such activities, especially offshore, precludes widespread utilization. Consequently, compartments must be identified without benefit of well testing.
- Europe (1.00)
- North America > United States > Texas (0.46)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Formation test analysis (e.g., wireline, LWD) (1.00)
- (3 more...)
Phase Behavior Study in the Deep Gas-Condensate Reservoir with Low Permeability
Qi, Zhilin (Zhongyuan Oil Field) | Liang, Baosheng (U. of Texas Austin) | Deng, Ruijian (Sinopec Zhongyuan Oil Field) | Du, Zhimin (Southwest Petroleum Institute) | Wang, Shouping (Sinopec Zhongyuan Oil Field) | Zhao, Wei (Sinopec Zhongyuan Oil Field)
Abstract Recently, more and more deep reservoirs are developed due to the appearances of new technologies. Among them, gas-condensate reservoirs, with high temperature, high pressure, and low permeability, account for a high proportion. As a result, not only gaseous formation water is needed to be considered, reservoir deformation and interfacial phenomena should also be included. It is a big challenge for conventional PVT analysis to acquire real phase behavior. In this paper, we considered the characteristics of reservoir formation and fluids under the conditions of high temperature, high pressure, and low permeability. Then, two models were developed: dew point prediction model for the oil-gas system, and the prediction model for retrograde liquid saturation during the constant volume depletion development. On the basis of hydrocarbon PVT experimental test with rich gaseous formation water, reservoir deformation and interfacial phenomena are further investigated. The models were applied to a deep gas-condensate reservoir with low permeability in Zhongyuan Oilfield, China. The results demonstrated that interfacial phenomena and reservoir deformation not only increased dew point, made the retrograde process earlier, but also aggravated the effects of retrograde condensation. Introduction Many deep and tight gas condensate reservoirs have been found recently. These reservoirs have high temperature, high pressure, low porosity and low permeability. High temperature increases the mutual solubility between hydrocarbon and water, such as irreducible water, edge water and movable interstitial water. Also, more gaseous formation water exists in the condensate gas and therefore has an impact on hydrocarbon phase behavior 1–3. Meanwhile, interfacial phenomena between porous media and fluids are prominent because the reservoir has fine rock grains, small pores and larger specific surface area 4–7. In addition, reservoir deformation during exploitation also affects phase behavior of the oil-gas system and reduces porosity and permeability 8–9. Since gaseous formation water, reservoir deformation and interfacial phenomena all contribute to the reservoir phase behavior, conventional PVT analysis could not acquire real phase behavior under the deep subsurface. In this paper, we studied the gas condensate system in Qiaokou reservoir, Zhongyuan Oil Filed. The phase behaviors are compared with and without gaseous formation water. Then, for the reservoir with rich gaseous formation water, dew point prediction and phase equilibrium calculation models are built. Further, such models are combined with the consideration of interfacial phenomena and reservoir deformation in the deep and tight gas condensate reservoir. Phase behavior testing for oil-gas phase with rich gaseous formation water We adopt the experiment approach proposed by Shi et al.10 for PVT test of well Q76, located in Qiaokou reservoir, Zhongyuan Oil Field. The phase behaviors of condensate gas and oil system are studied with and without gaseous formation water, respectively. The test focuses on dew point pressure and retrograde liquid saturation during the constant volume depletion. The temperature in the middle of Qiaokou reservoir is 135?. The composition of well Q76 effluent is shown in Table 1. The comparison test results are shown in Table 2 and Fig. 1, respectively. From the comparison experiments, we find that the existence of gaseous formation water raises the dew point pressure in the condensate gas and oil system, makes the retrograde process earlier, and increases the retrograde liquid saturation. Consequently, the retrograde condensate phenomenon is getting worse. Prediction models for phase behavior in deep low-permeability gas-condensate reservoir With pressure drop during reservoir recovery, heavy hydrocarbon in gas phase which is adsorbed on the surfaces of rock grains will gradually desorb and consequently affect the oil and gas compositions. Meanwhile, capillary condensation in porous media speeds up the occurrence of retrograde condensation. Therefore, interfacial phenomena have an impact on the process of oil-gas phase equilibrium. Additionally, pressure drop causes rock deformation to some extent, which further reduces the sizes of capillary tubes. As a consequence, the roles of capillary condensation and capillary pressure are enhanced.
- North America > United States (0.95)
- Asia > China > Henan Province (0.55)