In reservoir multiphase flow processes with high flow rates, both viscous and capillary forces determine the pore-scale fluid configurations, and significant dynamic effects could appear in the capillary-pressure/saturation relation. We simulate dynamic and quasi-static capillary pressure curves for drainage and imbibition directly in SEM images of Bentheim sandstone at mixed-wet conditions by treating the identified pore spaces as tube cross-sections. The phase pressures vary with length positions along the tube length but remain unique in each cross-section, which leads to a nonlinear system of equations that are solved for interface positions as a function of time. The cross-sectional fluid configurations are computed accurately at any capillary pressure and wetting condition by combining free energy minimization with a menisci-determining procedure that identifies the intersections of two circles moving in opposite directions along the pore boundary. Circle rotation at pinned contact lines accounts for mixed-wet conditions. Dynamic capillary pressure is calculated using volume-averaged phase pressures, and dynamic capillary coefficients are obtained by computing the time derivative of saturation and the difference between the dynamic and static capillary pressure. Consistent with previously reported measurements, our results demonstrate that, for a given water saturation, simulated dynamic capillary pressure curves are located at a higher capillary level than the static capillary pressure during drainage, but at a lower level during imbibition, regardless the wetting state of the porous medium. The difference between dynamic and static capillary pressure becomes larger as the pressure step applied in the simulations is increased. The model predicts that the dynamic capillary coefficient is a function of saturation and independent of the incremental pressure step, which is consistent with results reported in previous studies. The dynamic capillary coefficient increases with decreasing water saturation at water-wet conditions, whereas for mixed- to oil-wet conditions it increases with increasing water saturation. The imbibition simulations performed at mixed- to oil-wet conditions also indicate that the dynamic capillary coefficient increases with decreasing initial water saturation.
The proposed modelling procedure provides insights into the extent of dynamic effects in capillary pressure curves for realistic mixed-wet pore spaces, which could contribute to improved interpretation of core-scale experiments. The simulated capillary pressure curves obtained with the pore-scale model could also be applied in reservoir simulation models to assess dynamic pore-scale effects on the Darcy scale.
This presentation outlines an integrated workflow that incorporates 4D seismic data into the Ekofisk field reservoir model history matching process. Successful application and associated benefits of the workflow benefits are also presented. A seismic monitoring programme has been established at Ekofisk with 4D seismic surveys that were acquired over the field in 1989, 1999, 2003, 2006 and 2008. Ekofisk 4D seismic data is becoming a quantitative tool for describing the spatial distribution of reservoir properties and compaction. The seismic monitoring data is used to optimize the Ekofisk waterflood by providing water movement insights and subsequently improving infill well placement.
Reservoir depletion and water injection in Ekofisk lead to reservoir rock compaction and fluid substitution. These changes are revealed in space and time through 4D seismic differences. Inconsistencies between predicted 4D differences (calculated from reservoir model output) and actual 4D differences are therefore used to identify reservoir model shortcomings. This process is captured using the following workflow: (1) prepare and upscale a geologic model, (2) simulate fluid flow and associated rockphysics using a reservoir model, (3) generate a synthetic 4D seismic response from fluid and rock physics forecasts, and (4) update the reservoir model to better match actual production/injection data and/or the 4D seismic response.
The above-mentioned Seismic History Matching (SHM) workflow employs rock-physics modeling to quantitatively constrain the reservoir model and develop a simulated 4D seismic response. Parameterization techniques are then used to constrain and update the reservoir model. This workflow updates geological parameters in an optimization loop through minimization of a misfit function. It is an automated closed loop system, and optimization is performed using an in-house computer-assisted history matching tool using evolutionary algorithm.
In summary, the Ekofisk 4D SHM workflow is a multi-disciplinary process that requires collaboration between geological, geomechanical, geophysical and reservoir engineering disciplines to optimize well placement and reservoir management.
The Ekofisk Field is located in the Norwegian Sector of the North Sea. It was discovered in 1969 and began production in 1971. The field is one of the largest fields on the Norwegian Continental Shelf with initial oil in place estimate of 7.1 billion STB of oil. The produced volumes are extracted from two fractured chalk formations. These reservoir formations are characterized by very high porosities and low matrix permeabilities. Formation productivity is enhanced by the natural fracture systems that allow commercial production from the field.
The first field development phase was natural depletion production. The first pilot water injection was initiated in 1981, and large scale water injection was initiated in 1987.
Expected recovery factor have increased from an initial estimate of 17% OHIP (Original Hydrocarbon In Place) to a current estimate of more than 50% OHIP through continuous improvements in field development plans, implementation of IOR, application of new technology and investments in new and existing facilities. It is also believed that a significant upside exists in further development optimization.
Future development plans at Ekofisk include an active drilling program. The program includes replacement of mechanically failed wells coupled with new infill wells to optimize recovery. Conducting a successful drilling programme in a mature chalk field is challenging. A single wellbore can experience large reservoir pressure and water saturation differences. Furthermore, compaction can alter the target interval depth, thickness, and reservoir properties as a function of time.
This study introduces a decision making evaluation method for flexibility in chemical EOR. The method aims to capture the effects of dynamic uncertainties both technical and economic and produce a near-optimal policy with respect to these uncertainties as they vary with time. The evaluation method used was the Least-Squares MonteCarlo(LSM) method which is best suited for evaluating flexibility in project implementation. The decision analysed was that of finding the best time to initiate surfactant flooding during the life time of a field under uncertainty. The study was conducted on two reservoir models: 3-D homogeneous model and a 2-D heterogeneous model. The technical uncertainties considered were the residual oil saturation to the surfactant flood, surfactant adsorption and reservoir heterogeneity while the main economic uncertain parameters considered were oil price, surfactant cost and water injection and production costs. The results show that the LSM method provides a decision making tool that was able to capture the value of flexibility in surfactant flooding implementation. The LSM method provides great insight into the effect of uncertainty on decision making which can help mitigate adverse circumstances should they arise. The results found that the optimal policy obtained was reliable and that heterogeneity does affect the optimal policy. It was also possible to consider the value of information using this method.
Shojaikaveh, Narjes (TU Delft) | Berentsen, Cas (Delft U. of Technology) | Rudolph-Floter, Susanne Eva Johanne (Delft U. of Technology) | Wolf, Karl Heinz (Delft U. of Technology) | Rossen, William Richard
The injection of carbon dioxide (CO2) into depleted gas reservoirs and aquifers offer options for CO2-storage. Co2 sequestration is largely controlled by the interactions between CO2, reservoir fluid(s) in place and rock. In particular, the wettability of the rock matrix is a key factor for the fluid distribution and fluid displacement.
In this study, the wetting behavior of CO2-Bentheimer sandstone-water systems was investigated by means of visual contact-angle measurements. The experiments were conducted in a modified pendant drop cell (PDC) that allows captive-bubble contact-angle measurements at elevated temperatures and pressures. Contact angle measures were peformed with water that was fully (pre)-saturated with CO2. Multiple experiments were performed at constant temperature of 318K and pressures varying between 0.1-12 MPA which represent typical in-situ reservoir conditions. The experimental data shows that the contact angle and the size of the bubble converge to equilibrium in time. During this convergence period, the contact angle and the bubble size generally show a slight change as function of time. This can be contributed to the mass transfer and reduction in density of the CO2 during re-equilibration of the system. The experimental data shows a larger dependency of the contact angle on bubble size than on pressure. However, for bubbles with similar size, contact angle shows a slight increase as a function of pressure. However, for bubbles with similar size, contact angle shows a slight increase as function of pressure. All data shows that Bentheimer-water-CO2 systems remain water-wet even at high pressure.
CO2 injection is a proven EOR (enhanced oil recovery) method, which has been extensively applied in the field. CO2 promotes oil recovery through a number of mechanisms including; CO2 dissolution, viscosity reduction, oil swelling, and extraction of light hydrocarbon components of crude oil. One of the main advantages considered for CO2 injection is that it can develop miscibility with most of light crude oils at a pressure lower than what would be required for other gases. Miscibility development is a function of reservoir pressure, temperature and also oil composition. In water flooded oil reservoirs, water can adversely affect the performance of CO2 injection as it reduces the contact between oil and CO2. However, CO2 will be able to dissolve into water and diffuse from water into the oil. The dynamic interplay between these various mechanisms is complicated and cannot be captured by existing models and simulations.
In this paper we present the highlights of the results of a series of visualization (micromodel) experiments performed using three different crude oils. CO2 injection was carried out to investigate the pore-scale interactions between CO2, crude oil and water inside the porous medium under liquid, vapour and super-critical conditions. In particular, we reveal a new mechanism that can lead to the recovery of the disconnected oil ganglia that do not come to direct contact with injected CO2. Our results reveal that, under certain conditions, a new phase can be formed in trapped oil ganglia and grows in size and can eventually connect the ganglia to the flowing CO2 stream and lead to their production. The increase in the size of the new phase continues without limit as long as CO2 injection continues and is much more than what can be achieved by the swelling of the oil due to CO2 dissolution. In the injection strategies where CO2 injection is associated or followed by water injection, e.g. CO2-WAG or CO2-SWAG, formation of the new phase can also divert the flow of water towards the unswept regions of the porous media and lead to additional oil recovery.
van den Hoek, Paul (Shell) | Mahani, Hassan (Shell Intl. E&P Co.) | Sorop, Tibi (Shell) | Brooks, David (AAR Energy) | Zwaan, Marcel (Shell Intl. E&P Co.) | Sen, Subrata (Shell India Markets Private Ltd) | Shuaili, Khalfan (PDO) | Saadi, Faisal (PDO)
Polymers exhibit non-Newtonian rheological behavior, such as in-situ shear-thinning and shear-thickening effects. This has a significant impact on pressure decline signature as exhibited during Pressure Fall-Off (PFO) tests. Therefore, applying a different PFO interpretation method, compared to conventional approaches for Newtonian fluids is required.
This paper presents a simple and practical methodology to infer the in-situ polymer rheology from PFO tests performed during polymer injection. This is based on a combination of numerical flow simulations and analytical pressure transient calculations, resulting in generic type curves that are used to compute consistency index and flow behavior index, in addition to the usual reservoir parameters (kh, faulting, etc.) and parameters relating to (possible) induced fracturing during injection (fracture length and height). The tools and workflows are illustrated by a number of field examples of polymer PFO, which will also demonstrate how the polymer bank can be located from the data.
We implement a novel up-winding scheme for finite element mobility calculation using the computed velocities in a finite element finite volume (FEFV) unstructured-mesh simulator. In FEFV numerical method, the pressure and transport equations are decoupled. The pressure is calculated using finite elements, and the saturation is calculated using finite volumes. Each element is shared between several control volumes -- three for triangles and four for tetrahedrals. Consequently, the saturations used in calculating element mobilities - hence updating pressure - are unclear. Some researchers use the average value between the elemental control volumes, or the integration points of the finite elements. For three-dimensional spherical flow, this does not produce accurate saturations profiles when compared to the Buckley-Leverett reference solution.
In this paper, we present a new formulation to calculate the FE mobility. We use the velocity vector, which is piece-wise constant in first order elements, to find the upstream saturation—where the tail of velocity vector intersects an element. This novel approach produces more accurate saturation profiles than previous conventional method, and it better models multi-phase displacements in complex reservoirs. It can be easily implemented in current FEFV based simulators.
The paper highlights the importance of adequate characterization of capillary pressure effects when preparing a development plan for a greenfield gas condensate reservoir with a large transition zone (TZ).
Capillary pressure data from centrifuge or porous plate (semi-permeable membrane) are used to characterise the transition zone. It is essential that a representative set of sample measurements is obtained. Core laboratories are not capable to keep initial pressure-temperature conditions during capillary pressure measurements. Hence, the conversion from surface to reservoir becomes uncertain. Conversion utilizes interfacial tension and wettability angle which are quite unknown and can be predicted using different P-T charts. Finally saturation model depends on the way of: characterization - discrete Rock Types (RT) or tuned-up Continuous Functions (Leverett, Amaefule etc.); matching log saturation profile with the one observed in the model; welltest playback in terms of mobile water and drained volumes.
In this study, the authors present a systematic workflow on how capillary pressure should be incorporated in a dynamic simulation model pointing out example pitfalls and giving validation tips. The illustrated case shows that if one of the steps is missed or wrong assumptions are made, then the TZ and the production potential will be incorrect. In our example, the discretization of connate water saturation and capillary pressure curves on early stages resulted to 8% underestimation of GIIP. Moreover, results indicated that uncertainty in conversion of capillary curves (from surface to reservoir) gives 15-20% differences in outcomes (depending on development scenario). Also it demonstrates a strong impact on the length of production plateau, rate of wellhead pressure decline, compression start-up which are vital aspects for the development concept, especially during front-end-loading stage of the project plan. We feel that the procedures presented here (both for engineers and management) can serve as a guide for QC and possible failures when they are not applied.
The focus of this study is on the investigation of multiphase flow effects on the pressure transient analysis in layered reservoirs with cross flow. Virtually all studies on the subject of multiphase well test analysis have been carried out in single layer reservoirs. However, many reservoirs are found to be composed of number of layers whose characteristics are different from each other and the wells in such reservoirs may be completed and produced from more than one layer.
A novel technique is proposed based on replacing multi-phase multi-layer reservoirs with cross flow with an equivalent single phase single layer reservoir. To validate the proposed method, several reservoirs with different saturations were studied numerically and were compared with the results of the proposed model. The reservoir parameters such as phase mobilities, skin factor and average reservoir pressure are compared with actual values. It was found that reservoir parameters can be obtained accurately with the equivalent single phase single layer model. However, care should be exercised when horizontal saturation gradient is significant.
Keywords: well test, multiphase, multi layer, fluid saturation, cross flow
The Issaran field located 200 km east of Cairo-Egypt, is a heavy oil reservoir. The oil is of 8-12 degree API with viscosity of 4000 cps at standard conditions
Productivity of the wells has sharply declined due to increase in the water cut and increase in the formation skin value. The problem is attributed to the heterogeneity of the reservoir together with presence of fractures which is causing poor sweep efficiency plus the accumulation of hydrocarbon deposits.
The major challenge to remedy this situation was; 1) The creation of new extended flow channels. 2) Accurate placement of the treatment. 3) Diversion within the reservoir. 4) Provide sustain production increase. And 5) The flow and the production of oil through the newly formed wormholes.
A new innovative approach using a combination of acid based treating fluids and steam were used. Acid in combination with fit for purpose chemical diverting agent plus selective placement mechanism succeeded to open new production horizons and stimulate the existing one. The Addition of Steam has succeeded in reducing the viscosity and increasing the mobility of oil, and also in providing pressure support to the reservoir achieving further increase in the benefits of the acid stimulation.
The results of the treatments carried out so far have provided a new dimension in the enhanced recovery process of the heavy oil. This paper explains the design, execution, evaluation and the recommended way forward of this world first acid & steam production enhancement initiative for enhanced recovery process in the heavy oil reservoirs.