The Statfjord field entered into the blow down phase after 30 years of production. Production of injection gas and gas liberated from residual oil is the main production target in this phase. In some areas, the gas cap has been produced and the wells are producing mainly water until the solution gas is mobilized. These wells have gone through large changes in gas-liquid-ratio (GLR) and water-cut (WCT). Production tests from wells located in such areas have been used when analyzing the ability of multiphase-flow correlations to model vertical lift performance (VLP). Accurate modeling of the VLP is critical to predict a realistic production rate during the blow down phase.
Measured wellhead (THP) and downhole pressures from about 80 production tests, from four wells, were used to analyze the accuracy of VLP correlations at widely varying flow conditions (GLR, WCT, and THP). Altogether 17 multiphase pressure drop correlations incorporated in the program Prosper were tested by comparing observed and calculated downhole pressures.
Based on the production tests the ability of the different correlations to predict the VLP varies with the following top 4: Hagedorn Brown, Petroleum Experts, Petroleum Experts 2, and Petroleum Experts 3. These correlations are recommended if no measured data is available.
In general a somewhat low pressure drop is predicted at low gas-liquid ratio (GLR), and a somewhat high pressure drop is predicted at high GLR. After tuning, accurate predictability was observed for the different correlations for limited ranges in GLR e.g. 50-300 Sm3/Sm3. However, for larger ranges in GLR it was not possible to achieve an accurate VLP correlation, even after tuning. Hagedorn Brown and Petroleum experts seem to be the most accurate correlations for a wide range of producing GLR.
The error in the predicted production performance when a single VLP correlation is used can be substantial for highly productive wells with large variations in producing GLR. It is recommended to shift the tuning following the GLR development.
Calculating the pressure drop in the production tubing is important for well design, production optimization, and for generation of production prognosis. Many multiphase flow correlations are proposed. Still, none of them are proven to give good results for all conditions that may occur when producing hydrocarbons (Pucknell et al. 1993). Analysis of available correlations is often the best way to determine which one to use (Brill and Mukherjee 1999). Some will be good for liquid wells, whereas others for gas. Most of the correlations are to some degree empirical and will thereby be limited to conditions of which the correlations are based on (Pucknell et al. 1993).
Kashagan is a super giant offshore carbonate field which was discovered in 2000 by a consortium of oil companies (currently, affiliates of): ExxonMobil, ENI, Shell, TOTAL, Conoco-Phillips, INPEX and KazMunaiGaz. The field is located in an environmentally sensitive area of the North Caspian Sea. The field is a deep, large structural relief, over pressured, isolated, carbonate build-up with a high-permeability, karstified and fractured rim and relatively low-permeability platform interior. The field contains a sour, undersaturated light oil with a large gas content. High pressure miscible gas injection is planned for oil recovery enhancement, as well as sulfur management.
No-one doubts the importance of flow assurance in offshore projects in particular. Moreover, it is now well known that gas injection operations require the evaluation of asphaltene deposition risk. The consortium has undertaken extensive evaluations to ascertain the likelihood of any flow assurance risks from subsurface to surface. During the asphaltene risk evaluation, many bottomhole samples have been collected and analyzed for asphaltene content, asphaltene onset pressure (AOP), and SARA (saturates, aromatics, resins and asphaltenes). These continuous analysis efforts have revealed some anomalous results such as AOP being detected from some fluid samples while not being detected from others.
The apparently inconsistent AOP results are critical to understand how to guide flow assurance measures. Therefore, all available asphaltene data were re-assessed in all their aspects to attempt to clarify asphaltene risk. This paper presents a multidisciplinary approach where a synergy between reservoir engineering and geoscience (geology and geohistory) has been developed to explain AOP results for this complex fluid. The results should help flow assurance specialists to better define the asphaltene operating envelope, which will be used for reservoir and production operations optimization. In addition, these results should be useful for optimizing data-surveillance, flow assurance, and for defining new sample acquisition plans. These findings may also be helpful to minimize future sampling and fluids analysis while achieving reliable flow assurance. The paper will show examples of the related flow assurance analyses, and the geological information which were incorporated in the study, resulting in a detailed asphaltene matrix risk profile for this reservoir.
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.
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 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.
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
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.
In digital oil fields in which intelligent completions are used, information that can be provided by the intelligent completion technology is increasing in importance, as intelligent well completions can minimize the need for additional custom data-gathering solutions. Thus, industry-data interfacing standards for multiple devices and systems can be reduced. For assets using intelligent completions, solutions are attained by a combination of subsurface and surface or subsea sensors provided by several vendors.
Challenges arise when attempting to manage the interfaces required for providing real-time data from all points of interest (i.e., subsurface choke positions, flow, pressures and temperatures, wellhead positions, subsea facility readings, etc.). The design and implementation of an integrated data-applications system that can integrate data from multiple workflow sources for the purpose of maximizing field performance is the focus of this paper. The asset optimization applications acquire operating parameters from all points of interest, making them available to software modules designed to estimate key well-performance indicators.
The asset-optimization application discussed here is an integrated system that performs five services:
1. A data-interfacing methodology acquires data from multiple sources or directly from downhole devices.
2. The integration service converts the subsurface and surface data to engineering units of measured well parameters.
3. The well performance service uses well PVT and device-integration service values to execute complex calculations, like virtual flow metering, water-cut estimates, etc.
4. The human/machine/interface service provides visualization, trending, and querying.
5. The connectivity service facilitates structured data transfer to field historians.
The paper will explain how the system works and its implementation into fields of different scales and types to reduce information technology (IT) customization, simplify interfacing of multiple devices or systems, and accommodate evolutions in IT. Additional system benefits that include more efficient management of real-time data security, quality, redundancy, and mirroring will also be provided.
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.
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.