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The single well chemical tracer (SWCT) test can be used to evaluate an Improved oil recovery (IOR) process quickly and inexpensively. The one-spot procedure takes advantage of the nondestructive nature of the SWCT method. The single-well (one-spot) pilot is carried out in three steps. First, Sor for the target interval is measured (see Residual oil evaluation using single well chemical tracer test. Then an appropriate volume of the IOR fluid is injected into the test interval and pushed away from the well with water.
The pdf file of this paper is in Russian.
This study presents a process to investigate mass transfer between fracture and matrix in naturally fractured reservoirs. The study has three parts: (1) the effect of imbibition by capillary pressure Pc in matrix, (2) mass transfer between fracture and matrix through k*σ, and gravity drainage, and (3) combination of capillary pressure, gravity, and viscous forces.
The important results from this study are listed below.
Part-1: The counter current flow theory predicts the capillary pressure between two adjacent cells will have same value at equilibrium condition for both gas-oil and oil-water systems. In addition, the saturation in each cell has a tendency to approach a value where Pc=0 regardless the wettability of the Pc curve.
Part-2: Simulation shows injected fluid preferentially goes through high permeability fracture channel and mass transfer between fracture and matrix is mainly due to k*σ. Gravity drainage effect within a thick matrix block would be reduced due to low vertical permeability or k*σz. If k*σ=0, only viscous force is active.
Part-3: Initial estimate of critical water injection rate on oil recovery in field simulation can be calculated from dimensionless fracture capillary number derived from laboratory test. Then reservoir simulation is used to study the sensitivity of water injection rate to obtain optimal injection rate. In general lower injection rate would be favored due to lower viscous force and longer contact time with the matrix.
Bashiri, A.. (CAPE Center, Chem. Eng. Dept. Iran University of Sci. & Tech., Narmak, Tehran, Iran, Postal code: 1684613114, Postal box: 167651163) | Kasiri, N.. (CAPE Center, Chem. Eng. Dept. Iran University of Sci. & Tech., Narmak, Tehran, Iran, Postal code: 1684613114, Postal box: 167651163)
Abstract Heterogeneity of the hydrocarbon reservoirs can be defined in pore level or macroscopic scale. Pore level heterogeneity such as pore size and structure controls the quantity of hydrocarbon left (residual saturation) during production, whereas macroscopic heterogeneity determines zones that injected fluid sweeps (Franklin, 1994). During simulation of a reservoir, macroscopic heterogeneity is represented by assigning different rock properties (e.g. permeability and porosity) for different simulation grid blocks. However, due to complex nature of pore entrapment mechanisms, it is only possible to represent pore scale heterogeneity with empirical correlations. Capillary Desaturation Curve (CDC) is a suitable correlation that links residual hydrocarbon saturation to physical properties of a given reservoir in pore scale. Therefore, accurate representation of CDC pattern can be critical for Improved Oil Recovery (IOR) processes evaluation as pore information is used as the basis for residual saturation prediction. Application of CDC data for reservoir simulation and IOR has been reviewed here accordingly.
Abstract Oil recovery depends on geologic complexity – structure, stratigaphy and deposition – and rock and fluid properties. The work reported here illustrates the oil trapping mechanisms for 450 reservoirs in 83 mature deepwater fields in the Gulf of Mexico (DW GoM). The evaluation of trapped or forecast remaining was a precursor to determining improved oil recovery concepts as part of a project for the group RPSEA (Research Partnership to Secure Energy for America). Neogene age reservoirs in the DW GoM are characterized as over-pressured with generally good rock and fluid properties. Drive energy is typically from a combination of rock compaction with some assistance from aquifer influx. Only a few engineered water injection projects have been implemented and no gas injection has been used to add drive energy. Oil recovery is reasonable with an average of 32% of original oil in-place (OOIP) with a 95% confidence and range between 21% and 42% of OOIP. Several field examples of estimated trapped oil mechanisms are used to illustrate typical reservoir performance and the calculation methodology. Trapped oil is determined for the categories of capillary bound, non-connected to wells, high abandonment pressure or low abandonment water cut, limited drive energy, and poor sweep. The results indicate the improved recovery initiatives should focus on aqueous phase injection, pumping and artificial lift technology, and well and intervention technology.
Abstract Deepwater Gulf of Mexico oil fields typically get modest ultimate recovery factors in the 10% - 35% range because of challenging reservoir characteristics and high development costs. Yet the total target for Improved Oil Recovery (IOR) in deepwater (DW) Gulf of Mexico (GoM) is temptingly large, with about 44 Billion Bbl remaining oil expected to be left behind in discovered fields at abandonment. " Technical Gaps?? make most IOR processes impractical in an environment of high well costs, complex reservoirs, and substantial logistical challenges. This paper describes original work done through a project funded under the Energy Policy Act of 2005 and directed by the non-profit Corporation RPSEA (Research Partnership to Secure Energy for America). The study includes a review and analysis of the performance of 83 developed DW oil fields consisting of 415 individual reservoirs. Also, data has been collected and evaluated for 15 discovered and undeveloped Lower Tertiary, Paleogene fields. The work has assessed reservoir properties, original oil in-place, expected recovery factor, volume of projected remaining oil, and the mechanisms by which oil is trapped and not produced. The analysis of performance was then used to select a group of IOR processes which could target specific trapped oil mechanisms. The results presented here are lessons learned to date on field performance, the remaining oil target for IOR, the IOR processes being considered, and the future evaluation plan. An objective of the work is to determine the " Technical Gaps?? which currently prevent the economic implementation of selected IOR processes in the challenging conditions of deepwater GoM. Recommendations will be made for future Research & Development funding to address the technical gaps and to accelerate implementation of potentially high impact IOR processes. Introduction RPSEA is a non-profit Corporation used to oversee funding under the Energy Policy Act of 2005. Its mission is to facilitate cooperative effort to identify and develop new technology for exploring, producing and transporting energy. The current focus areas of RPSEA include ultra-deepwater, unconventional natural gas, and enabling small producers. The objectives of RPSEA project #07121-1701 are to identify IOR processes for deepwater GoM which could add substantial reserves and to identify the " technical gaps?? preventing their application. The recommendation of future R&D programs to bridge those technical gaps will be a deliverable from the work. The study will be conducted over 18 months at a projected total budget cost of $2MM. The first step of this investigation was to prepare a high-level estimate of the " Size of the Prize?? - the projected Remaining Oil In-Place (ROIP) in deepwater Gulf of Mexico which is the target for IOR. A database was compiled for 83 producing fields and 415 reservoirs including original oil in-place (OOIP), projected recoverable oil, and key reservoir properties. The sources of information are from ReservoirKB (copyright Knowledge Reservoir, LLC) and the Minerals Management Services (MMS).
IOR methods, for this study, consist of Comparing these criteria with values from processes in which an injection fluid is the reservoir of interest yields an indication used to improve the recovery of oil from a of success of the IOR projects Defining qualitative variables was another hydrocarbon reservoir. IOR includes the By its nature, screening can be considered data-quality issue. Aquifer strength was following processes: waterflood; miscible only a coarse judgment on the suitability of particular concern.
Abstract The choice of an Improved Oil Recovery (IOR) process for use in a particular reservoir depends on several factors; the habitat of residual oil, the properties of the reservoir fluids, reservoir conditions and reservoir heterogeneity. Reservoir heterogeneity exists at all scales, from the micro to the mega-scopic. Previous workers have studied the effects of micro and meso-scale heterogeneities on IOR processes in detail, as many processes are designed to act at those scales, but have ignored macro-scale heterogeneities such as facies variations. These can have a large effect on an IOR process; controlling the magnitude and nature of the connectivity between wells, compartmentalising the reservoir and influencing the balance of capillary, viscous and gravity forces. A database of 499 IOR projects in clastic reservoirs was collated. The macro-scale heterogeneity present in each reservoir was categorised by depositional environment using the Tyler and Finley Heterogeneity Matrix. The results show that successful IOR projects using a particular process cluster at certain combinations of lateral and vertical heterogeneity. To investigate the distributions, a quantitative method of evaluating macro-scale heterogeneity was devised. These Lateral and Vertical Heterogeneity Indices (LHI and VHI) provide a simple method of summarising and communicating geological information between different people and disciplines. Reservoirs with known levels of LHI and VHI were modelled, in which various IOR processes were simulated. Over 350 simulations of steam, polymer and Water Alternating Gas (WAG) injection processes were run and used to identify the processes that worked best under different levels of heterogeneity, dip and net to gross. The results showed that the Heterogeneity Indices can be used to predict the effect of macro-scale reservoir heterogeneity on these three processes and that objective, geologically based screening criteria could be derived. Using these criteria, it is demonstrated that in the high cost and low well density environment of the North Sea, WAG injection is the most viable IOR process, as the efficiency of the process is relatively unaffected by macro-scale heterogeneity. Introduction An oil reservoir is a complex system of interconnecting pore spaces filled with a two or three phase fluid. This complexity, coupled with the depletion of the natural drive mechanism, often means that only a percentage (10 to 60%) of the total oil in place can be produced by primary and secondary recovery. Improved Oil Recovery (IOR) processes have been developed to increase this proportion. The choice of IOR process for use in a particular field depends on the habitat of residual oil, fluid properties, reservoir conditions and reservoir heterogeneity. Reservoir Heterogeneity exists at all levels from the micro-scopic to the mega-scopic, illustrated in Fig. 1.Micro-scale heterogeneity in properties such as permeability, porosity and capillary pressure control the oil storage potential, fluid flow rates and residual oil (µ metres) Meso-scale heterogeneity is a function of sedimentary structures, ripples, cross bedding (cm to m). Macro-scale heterogeneity is created by the arrangement of individual sand and shale bodies within the reservoir. This architecture defines the direction of fluid flow between wells, determines how a reservoir drains and where hydrocarbons remain unrecovered. (1m to 100's of metres) Mega-scale heterogeneity is a product of the juxtaposition of major depositional elements, different depositional environments or large-scale fault compartmentalisation, creating traps and reservoirs. (>1000 metres) Micro and meso-scale heterogeneities have been studied in detail by previous workers in the field of IOR because many IOR processes are designed to act on those scales. While papers such as Taber et al. provide very useful screening criteria based on porosity, permeability and reservoir fluid parameters, little data is presented on the impact of larger scale geological heterogeneity.
The application of Improved Oil Recovery (IOR) techniques allows the economic value of existing fields to be maximised, through increased oil recovery and field life extension. This is especially important in mature fields, as oil production rates decline and water production increases. Environmental considerations also favour IOR projects, since they can reduce the need for new green field developments, provide a means of utilising unwanted associated gas production and ultimately a disposal route for CO2.
Identifying appropriate projects in a field portfolio can be a difficult task, because of the large number of IOR techniques and reservoir combinations that need to be considered. Furthermore, projects may not go forward because the perceived balance between the rewards and the risks is not considered to be competitive compared to other more conventional options, such as further development drilling or exploration and the subsequent appraisal and development of new fields. In this paper, tools and methodologies will be described that provide a systematic approach for evaluating technical and economic IOR potential within a risk management framework. This three stage approach enables IOR projects to be compared directly with conventional exploration and development projects, based on an assessment, rather than a perception, of the balance between rewards and risks.
During the first stage, the MAESTRO tool is used to provide a rapid initial assessment (screening) of IOR potential within a field portfolio, estimating the technical viability, incremental recovery and economics of each combination of reservoir and IOR technique. This allows possible projects to be ranked so that clearly unviable processes can be eliminated and priorities set for the subsequent stages of evaluation. In stage two the remaining projects are assessed using "prospecting" simulations to examine the recovery mechanisms in more detail and to establish base case economics. Some of the important reservoir specific parameters that control the IOR processes will not be known at this time. Experience is used to define credible sets of process parameters, taking into account typical distributions of values, the cost of subsequently determining them and the potential project rewards. Even at this level, good reservoir engineering is needed to ensure that IOR projects are not prematurely eliminated. Only projects with economic base cases proceed to the final stage of evaluation, a programme of detailed appraisal and project design work, which may include the acquisition of additional field or laboratory data.
The prospecting simulations and detailed appraisal studies are conducted in a risk management framework. Risk assessment tools are used to quantify project risk and identify the Critical Project Parameters (CPPs), where uncertainty has most impact on project performance. Proactive risk management techniques, including improved project design, key data acquisition and contingency planning are used to improve the balance between project return and exposure.
The application of Improved Oil Recovery (IOR) techniques allows the economic value of existing fields and near field hydrocarbon resources to be maximised, through increased oil recovery and field life extension. In addition to the direct economic benefits of IOR projects, significant environmental benefits can also be realised:
By extending field life the need for green field developments is partly reduced.
Hydrocarbon gas injection based IOR schemes can provide a means of avoiding flaring of associated gas where this cannot be exported to the gas market because of its quality (e.g. H2S content) or the cost of developing export infrastructure.
CO2 based IOR schemes can provide a disposal route for CO2 and reduce greenhouse gas emissions.
Kumar, Mridul (Chevron Petroleum Technology Company) | Akshay, Sahni (Chevron Petroleum Technology Company) | Alvarez, J.M. (PDVSA-Intevep) | Heny, C. (PDVSA-Intevep) | Vaca, P. (PDVSA-Intevep) | Hoadley, S.F. (Chevron Global Technology Co., Boscan ) | Portillo, M. (Chevron Global Technology Co., Boscan )
Chevron and Pdvsa-Intevep jointly conducted an evaluation of improved oil recovery (IOR) opportunities for the Boscán field to increase oil recovery and to help maintain future production rate. The shallower, northern area of the field was the target of this evaluation. Based on process screening results of Phase I, steam injection, waterflooding, and diluent/solvent injection were selected for a more detailed evaluation in Phase II.
During Phase II, fine-grid, geological models were built for the northern part of the field. In addition, laboratory experiments were conducted to obtain necessary data. The geologic model and input data were first validated using primary production data from representative wells. Numerical simulation studies for steam injection and waterflooding were conducted on three different segments to capture geologic variability. Effects of operating conditions and important uncertainties of input parameters on production forecast were obtained.
Results show that IOR processes have significant upside oil recovery potential. However, considerably smaller well spacing (well spacing of 290-m or pattern spacing of 54-acre or less) will be needed for floods. Only cyclic process can work at current spacing. Steamflooding results in the highest recovery (up to 43% OOIP). Cyclic steaming provides opportunity for accelerated recovery prior to steamflooding. Laboratory diluent injection appears promising but needs further evaluation.
The Boscán field lies 40-km southwest of Maracaibo, Venezuela (see Figure 1) and covers an area of approximately 660 km2. The field produces a 10.5°API gravity asphaltic oil from the Eocene Misoa formation, with a live oil viscosity ranging from 200-400 cp at reservoir conditions. The reservoir dips to the southwest and ranges from 5000 to 9000 ft in depth. Boscán was originally developed at 1000-meter spacing and has been on primary production since 1949. Infill wells have now reduced the spacing to 600 meters in portions of the field. Gullon presents a good overview of the Boscán field and notes that the field may have in excess of 26.4 billion barrels of original oil in place. The ultimate recovery by primary production is expected to be low (< 7-8% OOIP).