Analytical solutions for the initial stage of one-dimensional countercurrent flow of water and oil in porous media are presented. Expressions are obtained for the time dependence of the water saturation profile and the oil recovered during spontaneous countercurrent imbibition in rod-like, cylindrical and spherical cores for which water is the wetting liquid. Some of the analytical solutions are found to be in good agreement with existing numerical solutions and available experimental data for oil recovery from cores with strong water wettability.
Capillary-driven fluid flow is often important in two-phase flow in fractured porous media and in layered media where individual layers are thin. In such cases, the parameters in the flow equations are complicated functions of saturation due to high nonlinearity arising from a realistic shape of the capillary-pressure curve. The common approach to the problem solution is the use of numerical techniques.
Analytical solutions to fluid flow problems are desirable, because they allow a better understanding of the underlying physics and verification of numerical models. For capillary-driven flow, only a handful of authors have proposed analytical solutions of various degrees of complexity and with certain restrictive assumptions.
Yortsos and Fokas  obtained an analytical solution for a one-dimensional flow with account of capillary pressure; the relative permeabilities and capillary pressure were, however, severely restricted in functional form. Chen  proposed combined analytical-numerical techniques for analysis of radial one-dimensional flow. His work is based on the use of certain asymptotic conditions; it has a strong numerical component.
McWhorter and Sunada  reported quasi-analytical solutions for one-dimensional linear and radial flow. Their work includes both countercurrent and cocurrent flow. These authors limited their solution to an infinite acting medium and assumed that the volume flux at the inlet is of the form At-1/2 where A is constant and t is time.
Pavone et al.  also solved the one-dimensional and two-dimensional (gravity drainage) problem analytically; several assumptions were made by these authors to provide a closed-form solution. The assumptions included (i) infinite gas mobility, (ii) linear liquid-phase relative permeability, and (iii) capillary-pressure dependence on saturation in the form of logarithmic function. As a result of these assumptions, the flow equations became linear.
In this paper, we provide approximate analytical solutions for the initial stage of linear, cylindrical and spherical countercurrent flow of water and oil in a porous medium. We solve the flow equations without restricting the functional form of the relative permeabilities and the capillary pressure. We only assume that the imbibing and the displaced liquids are incompressible and that the porous medium is water-wet. These two assumptions have been made in the work of all authors referred to above.
The "Diffusion" Coefficient
The flow of water and oil in a porous medium is described by a diffusion-type equation in which the quantity
plays the role of diffusion coefficient [McWhorter and Sunada, 1990; Pooladi-Darvish and Firoozabadi, 2000]. In this expression Sw is the water saturation, k (m2) is the absolute permeability of the medium, krw and kro are the relative permeabilities to water and oil, respectively, µw (Pa.s) and µo (Pa.s) are the viscosities of water and oil, respectively, f is the fractional porosity of the medium, Pc=po-pw is the capillary pressure (positive when water is the wetting liquid), and pw (Pa) and po (Pa) are the water and the oil pressures, respectively.
A methodology for constructing an analogue 3D model for clastic reservoirs in an estuary-shoreface depositional environment using outcrop information is discussed. Such analogue models provide valuable information related to reservoir architecture and rock properties that can be used to model sedimentary structures in the subsurface. A new approach for upscaling high-resolution models using nonuniform coarsened grid is introduced. Simulation results for a viscous dominated flow process show that nonuniform grids yield better results compared to uniform grids.
Hydrocarbon accumulations in estuary-shoreface type depositional environment are found at numerous locations worldwide. Complex sub-tidal and inter-tidal estuarine channels and shoreface deposits make these reservoirs extremely heterogeneous and difficult to model based on the information available at a few wells. Developing a detailed, high-resolution analogue model based on extensive outcrop data provides valuable information pertaining to spatial variations in reservoir architecture and rock properties. Information available on analogue models can be used to generate high resolution, stochastic models that are constrained to information such as well data, seismic attribute maps, etc. In order to utilize these equi-probable stochastic models for assessing production performance of the reservoir, a robust technique for upscaling the high-resolution models is necessary.
This paper addresses two important aspects of reservoir characterization: (1) Construction of an analogue model for clastic reservoirs in an estuary-shoreface depositional environment; and, (2) Development and validation of a new approach for upscaling high-resolution reservoir models using a nonuniform coarsened grid.
Analogue models are an important first step towards generating high-resolution stochastic models for reservoirs with complex depositional systems. Outcrops provide valuable information related to reservoir heterogeneity that can be used to model sedimentary structures in the subsurface. The proposal is to utilize outcrops of the upper Cretaceous Virgelle Member of the Milk River Formation in southern Alberta, Canada for developing the analogue model. This was a progradational depositional system representing environments from marine offshore through shoreface and foreshore1. The presence of sub-tidal and inter-tidal estuarine channels is a typical feature of such deposits. A consistent methodology for assembling outcrop data available on multiple 2-D sections, into 3D gridded models is presented. The approach integrates permeability and porosity measurements, stratigraphic columns, multiple vertical sections, and facies information to form a deterministic model for the clastic reservoir.
Modern geostatistical reservoir modeling techniques, such as stochastic methods, are routinely used to generate multiple, equally probable models, each optimally constrained to the available data. These models quantify the uncertainty associated with sparsity of information. Unfortunately, these models are often too large and the resulting flow models are extremely cpu demanding. Upscaling methods try to reduce the size of these detailed models without loss of accuracy. The proposed algorithm first identifies regions of high connectivity using streamline simulation. The nonuniform coarse-scale grid is then constructed preserving areas with high connectivity. This method preserves the geological and flow characteristics better than uniform upscaling techniques.
Using outcrops for modeling
The evaluation of critical factors associated with estuary-shoreface clastic reservoirs can be improved using data from analogue outcrops where large and small-scale heterogeneities can be studied in more detail. Excellent outcrop conditions allow continuous tracing of sedimentary units over large areas leading to a better understanding of reservoir architecture.
Physically and mathematically rigorous improved models, considering equilibrium and nonequilibrium diffusion gas transport in the liquid phase and resistance of the gas-liquid interface to gas dissolution in liquids, are developed. This allows the accurate determination of the gas diffusion coefficient from experimental measurements of the gas pressure decline in a closed tank by dissolution of gas in the liquid. The short- and long-time solutions of these models are derived analytically under various conditions. These solutions are reformulated for direct determination of the best estimate of the diffusion coefficient by regression of the resultant analytical expressions to experimental data. Procedures are presented and demonstrated for accurate estimation of the gas diffusivity coefficient by conforming the present models to experimental data.
The results developed in this paper can be utilized for determination of the gas diffusivity and the rate of dissolution of the injection gases used for secondary recovery and the rate of separation of light gases from reservoir oil and brine. The present analytic expressions can be facilitated to establish the significance of the equilibrium vs. nonequilibrium conditions under in situ conditions for gas injection, including carbondioxide, nitrogen, and methane. The gas diffusivity in drilling muds and completion fluids can also be determined using the present analytical interpretation methods.
Gas diffusivity is an important parameter determining the rate of dissolution of the injection gases used for secondary recovery and the rate of separation of light gases from the reservoir oil and brine. The frequently used equilibrium assumption in reservoir simulation may lead to significant errors in the prediction of oil recovery by miscible flooding and the miscibility can be optimized for best recovery by developing proper gas injection strategies.
Laboratory measurement of gas diffusivity in liquids is usually accomplished via the measurement of the pressure of gas in contact with certain liquids, such as oil, brine, drilling muds, and completion fluids, in a closed PVT-cell (see Fig. 1) during gas dissolution in the liquid phase. The accuracy of the available models, including by Riazi1, Sachs2,3, Zhang et al.4, are limited by their inherent simplifying assumptions involved in their analytic treatise used for interpretation of the experimental data. Zhang et al.4 have shown that there is no consensus amongst the available simplified models used for diffusivity measurement.
The purpose of this paper is to show how to estimate geomechanical parameters for improved recovery and coalbed methane production processes using an integrated flow model. An integrated flow model combines a petrophysical model with a traditional flow simulator. The usefulness of reservoir geophysical information from an integrated flow model is discussed for the following scenarios: forecasting the reservoir geophysical response of CO2 injection in a mature oil field; estimating subsidence during depletion of an oil reservoir with a gas cap; and predicting the change in geomechanical properties during the life of a coalbed methane reservoir.
The purpose of this paper is to show how to estimate geomechanical parameters for improved recovery and coalbed methane production processes using an integrated flow model. An integrated flow model combines a petrophysical model with a traditional flow simulator. The integrated flow model was originally devised to assist in the design and analysis of timelapse seismology 1-3 because the petrophysical model can calculate such reservoir geophysical attributes as acoustic impedance, reflection coefficient, shear velocity, and compressional velocity. We have found that integrated flow models have other important uses.
Using the integrated flow model, we can readily calculate such geomechanical properties as Poisson's ratio, Young's modulus, and uniaxial compaction. These properties are calculated from a minimal input data set and are provided throughout the life of the reservoir. They give us insight into the behavior of the structure of the reservoir and the impact of structural changes on fluid flow.
The usefulness of reservoir geophysical information from an integrated flow model is discussed for the following scenarios: forecasting the reservoir geophysical response of CO2 injection using advanced well technology in a mature oil field; estimating subsidence during depletion of an oil reservoir with a gas cap; and estimating the change in geomechanical properties during the life of a coalbed methane reservoir. The petrophysical algorithm used in the integrated flow model is described first.
A prototype integrated flow model (IFLO) based on a widely used petrophysical model has been developed and applied to a range of reservoir systems3,4. The petrophysical model must be able to calculate reservoir geophysical attributes that can be compared with seismic velocity and impedance measurements. The algorithm for calculating seismic velocities is a rock physics model5. We refer to the algorithm used in the integrated flow model as a petrophysical algorithm because of its dependence on rock physics properties and petroleum fluid properties.
Bulk density for a porous rock with porosity f is given by ?B=(1-)?m+f?f. Rock matrix density ?m and initial porosity are user-specified input data. Porosity depends on fluid pressure P and porosity compressibility cf =(1/f) (?f / ?P)T at constant temperature T. Oil, water and gas densities (? o, ?w, ? g) and saturations (S o,Sw,Sg) are needed to calculate fluid density ?f. Phase densities are obtained from the fluid properties model in the traditional flow simulator, and saturation distributions are obtained as solutions of the flow equations.
Reddy, B.R. (Halliburton Energy Services, Inc. ) | Eoff, Larry (Halliburton Energy Services, Inc. ) | Dalrymple, E. Dwyann (Halliburton Energy Services, Inc. ) | Black, Kathy (Halliburton Energy Services, Inc. ) | Brown, David (Halliburton Energy Services, Inc. ) | Rietjens, Marcel (Halliburton Energy Services, Inc. )
This paper describes a material derived from natural sources that can be used to crosslink a variety of polymers over a broad temperature range to produce gels for conformance applications.
Delayed crosslinked polymer systems have been used for many years in conformance applications. For the past decade, the most widely used system has been based on chromium (+3) crosslinked polyacrylamide. Organic crosslinkers, such as phenol/formaldehyde and polyethyleneimine (PEI) have also been used with a variety of polymers. However, these systems are being scrutinized by governmental agencies and have been scheduled for phase-out in some countries. Because of these issues, a single, environmentally friendly crosslinker that could be used with a variety of polymers over a broad temperature range was the focus of this study.
This paper details the laboratory development of an environmentally friendly, natural polyamine crosslinker system. This crosslinker can be used with a variety of polymers, such as polyacrylamide, AMPS/acrylamide, or alkylacrylate polymers. Gels ranging from stiff and ringing type to "lipping" gels have been obtained. The data illustrate a simple, commercially available system that can be applied to field operations. Potential crosslinking mechanism(s) of the system will be discussed.
Water production in oil-producing wells becomes a more serious problem as the wells mature. Remediation techniques for controlling water production, generally referred to as conformance control, are selected on the basis of the water source and the method of entry into the wellbore. Treatment options include sealant treatments and relative permeability modifiers (also referred to as disproportionate permeability modifiers). This paper primarily discusses water control with water-based gels for applications in wells in which the oil- and water-producing zones are clearly separated and can be mechanically isolated.
Chromium (+3) crosslinked polyacrylamide gels can be choice materials for matrix-fluid shut-off systems.1-4 The crosslinking reactions in these gel systems take place by the complexation of Cr (+3) ions with carboxylate groups on the polymer chains (Fig. 1).
Because of the nature of the chemical bond between Cr (+3) and the pendant carboxylate groups, formation of insoluble chromium species can occur at high pH levels. Other problems with these systems include thermal instability, unpredictable gel times, and gel instability in the presence of chemical species that are potential ligands. The gel times are controlled by the addition of materials, which chelate with chromium in competition with the polymer-bound carboxylate groups.5,6 Perhaps the most important drawback for the chromium-linked gels is the toxicity concern with the metal, despite the fact that a +3 oxidation state is less toxic than a +6 oxidation state.
Another popular water-based gel system for water-control applications is based on a phenol/formaldehyde crosslinker system for homo-, co-, and ter-polymer systems containing acrylamide.7-11 Depending on the polymer composition, these gels are thermally stable, and the gel times are controllable over a wide temperature range. The crosslinking mechanism involves hydroxymethylation of the amide nitrogen, with the subsequent propagation of crosslinking by multiple alkylation on the phenolic ring (Fig. 2).12,13 Several variations of the same technology were created to overcome the toxicity issues associated with formaldehyde and phenol. These processes generally involve replacing formaldehyde and phenol with less toxic derivatives that generate phenol and formaldehyde in situ, or are themselves active components of the crosslinking system. For example, formaldehyde can be replaced with hexamethylene tetramine (HMTA), glyoxal, or 1-, 3-, or 5-trioxane. Substitutions for phenol included phenyl acetate, phenyl salicylate, or hydroquinone, among others.12,13 Extensive patent literature for this technology exists.14-22
This paper presents new analytical relationships describing pattern waterflooding that have not been reported previously. The relationships fill a significant gap in the existing steady-state flow theory for two-phase, isotropic reservoir systems. The new equations, which include modifications for reservoir heterogeneity and skin effect, represent a general, comprehensive pattern flow theory that unifies previous works while greatly extending the range of applicability to all patterns and mobility ratios. These relationships facilitate understanding that is not provided by existing waterflooding theory of the absolute and relative flow performance of the various patterns in all mobility systems. A rational, analytical approach to waterflood optimization is presented here.
The economics of a waterflood depend upon two primary variables which engineers seek to optimize when designing a flooding scheme: (1) the processing, or throughput rate, and (2) the incremental oil recovery. Depending on the characteristics of the reservoir, one of these objectives can take a more dominant role in the determination of the optimum flooding pattern. For example, if there is significant permeability anisotropy, incremental oil recovery will take precedence because of the strong dependency of recovery on producer - injector orientation. Conversely, in isotropic reservoirs, considerations of flow rate will drive pattern selection, since incremental recovery in these reservoirs is dictated primarily by the mobility characteristics of the system and not by pattern type. In both types of reservoirs, an adequate recovery rate is paramount to an economically viable project.
However, when attempting to design the optimum pattern in isotropic reservoirs, one quickly finds that the existing body of waterflooding literature does not provide the information necessary to optimize the flow performance of waterfloods in all mobility systems. While waterflooding has a well-established technical basis, the two-phase flow theory of pattern waterflooding is incomplete. Specifically, it has not been possible to calculate analytically the absolute and relative flow performance of all patterns in all mobility systems. Also, it has not been shown how the flow performance of the various patterns compare in a relative sense with respect to the mobility characteristics of the reservoir system, nor what pattern selection criteria should be used to optimize waterflooding rates. This paper addresses these shortcomings by presenting new analytical relationships describing the two-phase, steady-state flow performance of repeated patterns in isotropic reservoir systems. The new relationships, which include modifications for heterogeneity and skin effect, represent a general, comprehensive pattern flow theory that unifies previous works while greatly extending the range of applicability to all patterns and mobility ratios. This is accomplished by showing the relationship between pattern average reservoir pressures and flow rates. Shown is how pattern average pressures and flow rates are a function of the producer/injector ratio, P/I, and a newly defined total mobility ratio, MT. Depending on MT, substantial differences can exist in the throughput rates achievable with the different patterns within a given reservoir. For any total mobility ratio, there exists a pattern, or producer/injector ratio, that provides the highest flow capacity relative to all others. The relative differences in flow capacity become more pronounced as MT gets further away from unity. As also shown, MT can be correlated to endpoint mobility ratio, M, and oil relative permeability curve shape for the pre-water-breakthrough period. The correlation is based on numerical results, and is useful in determining the economically optimum waterflooding pattern in isotropic reservoirs using the equations presented. The new equations apply equally well to augmented waterfloods, such as polymer floods.
The application of artificial intelligence tools such as fuzzy logic and neural networks is evolving as an oilfield technology. Log analysis work done in 1989 by Halliburton focused on applying backpropagation neural networks to identify total porosity and to identify lithofacies. In 1996 PRRC researchers used fuzzy logic to prioritize the significance of petrographic attributes to minipermeameter permeability measurements. Recently (2001), Zadeh Institute workers revisited the use of these tools in a manner consistent with soft computing terminology. In this paper, fuzzy ranking is used to prioritize inputs to neural networks that are trained, tested, and used to forecast oil production.
Patterns related to oil production are sometimes obvious in datasets from easy-to-interpret logs, but sometimes they are not, such as those in datasets from logs run through thin-bedded turbidite zones. The correlation between the individual log charts and core measurements varies from "good" to "bad" (fuzzy).
A neural network can be used to generate regressions when given the "good" log charts. The regression equations are developed with several log charts and core measurements and the resulting pseudo-logs are then correlated with known production. The resulting correlations can be used to estimate future oil production from potential producing wells.
Two field examples are used to demonstrate the fuzzy ranking technique and production forecasting correlations. The method to generate fuzzy curves is presented and sources of public domain neural networks are included in the references. The pitfalls involved in training and testing a neural network to predict oil production are also presented.
The need to forecast oil production is well known. From AFEs to bank loans, a supporting production forecast is required. Forecasting methods vary from decline curve extrapolation to computer simulation to analogy. This paper applies fuzzy ranking1 and neural networks2 (artificial intelligence tools) to develop correlations (analogies) to forecast oil production, given open-hole log information in one example and regulatory hearing information in another The neural networks are trained, tested, and then used to forecast oil production.
The application of artificial intelligence tools such as fuzzy logic and neural networks is evolving as an oilfield technology. Log analyses work done in 1989 by Halliburton focused on applying backpropagation neural networks to identify total porosity and to identify lithofacies.3 In 1996 PRRC researchers used fuzzy logic to prioritize the significance of petrographic attributes to minipermeameter permeability measurements.4 Recently (2000), Zadeh Institute workers revisited the use of these tools in a manner consistent with soft computing terminology.5
Statement of Theory and Definitions
Decline curve analysis, black oil model history matching, exploration analogies and exploration trend extrapolations are often considered statistical methods of forecasting oil production based on previous experience. However, it is generally difficult to forecast oil production because these sorts of analyses include data interpretation that is subjective and does not clearly relate to the future. For example, the proper decline rate must be established (pick the right slope), the computer model must be tuned to match production history, the depositional environment and oil source must be identified, and the reservoir geology must be understood. Oil forecasts of this nature can also be considered as inverse problems that are well suited to multivariate correlating techniques such as neural networks, but neural networks require input variables that relate to production performance. Selection of the proper variables available in the historical record is needed to most accurately forecast oil production. The variables included in data collected during the past that best relate to oil production can be identified with fuzzy ranking technology.
Gas production from gas fields and underground gas storage is usually accompanied by substantial water production. The high water production and necessity of on-site water liquidation often deteriorate the recovery efficiency and hamper maintaining an environmentally friendly production. During the past decades intensive R&D activity has been made to develop a viable well treatment method, however on account of the inverse mobility ratio in gas/water system, the conventional water shut-off or profile correction methods could not be used successfully under field conditions. According to some proposals the most promising procedure might be the injection of a high salt-containing polymer solution into the wells utilizing the reversible swelling/shrinking properties of the adsorbed polymer layer. If this mechanism works properly, a disproportional permeability modification is resulted and hence, the water productions is significantly decreased.
In contrast to mentioned technical solution the new idea is to use a "poor" solvent for preparation of the treating solution. The concept is based on the fact that the "solvent power" worsens as the alcohol content in the aqueous phase is increasing. A detailed laboratory study has been made in order to optimize the alcohol type and concentration, and different polymers were used as model to demonstrate the feasibility of the theoretical considerations. Complex rheological measurements served to study the flow properties of treating solutions and to determine the molecular conformation in bulk and adsorbed states. Sophisticated hydrodynamic measurements were carried out to demonstrate the disproportional permeability modification in gas/water systems and in different porous media. Finally, the general procedure was up-scaled to field conditions and the technology was tailored to individual well conditions. In the frame of the pilot test four gas wells operating at the largest Hungarian gas field were treated with alcohol-containing polymer solutions. The pilot tests were supported with sophisticated reservoir engineering supervision and the results were evaluated meticulously by academic and practical experts. According to the available data two treatments proved already positive, one of them showed outstanding performance. At the present time the observations are continued and new treatment project is planned by the operator. The paper outlines the whole innovation process and gives a concise summary of the lessons to learn.
Since the utilization of clean energy represents primary objectives all over the world, restriction of water production in gas wells is fundamental not only for petroleum engineering but also for the mankind. Therefore, substantial efforts had been made during the past years with the aim at developing suitable well treatment methods which may offer an effective, profitable and simple solution for high water production in gas fields and underground gas storage. However, on account of the inverse mobility ratio in gas/water system compared to oil/water case, viz. the flow of a fluid having the lower mobility must be restricted, the conventional and routinely applied water shut-off or profile correction methods (e.g. gels) can not be used for restriction of water production in gas wells. The only promising idea seems to be the utilization of disproportional permeability modification by polymer solutions and weak gels as proved by literature data and a few field pilot tests1-8. Despite some encouraging field results published recently by Zaitoun at al.5,8 we may realize that the basic problems has not been solved so far and on the other hand, a successful technique has great potential also in Hungary, a detailed laboratory research programme followed by field experiments were launched a decade ago. The present paper gives a concise summary of the laboratory studies, field results and the lessons to learn.
This paper presents a case study of a successful hydraulic fracturing campaign in the Arman field in western Kazakhstan: the first large scale campaign ever performed by a western service company in Kazakhstan. The Arman field is a mature field, originally delineated in Soviet times, and currently producing from four of the original vertical wells, and from newly drilled deviated (30 to 60 degree) wells. The field is currently under waterflood in three of the producing zones, but formation water is also being produced from wet zones. There is significant gas production, since the wells are all producing below the bubble point, either with ESP's or rod pumps.
We believed that hydraulic fracturing had good potential for stimulation in this field since most of the wells were producing with a positive skin. In addition to the positive skin, the reservoir was normally pressured, and also depleted in some zones, limiting the amount of drawdown to about 1000 psi. The wells were also producing water and gas in addition to oil, which further reduced the oil production (by a variety of mechanisms).
In this paper, we first describe the hydraulic fracturing operations, and the specific actions taken to deal with difficult features of this reservoir. We then examine the production mechanisms in the reservoir and compare the pre and post-fracture production data. Finally, we evaluate the effectiveness of hydraulic fracture stimulation as a method for improving oil recovery in this type of moderate permeability reservoir under waterflood.
In the spring of 2000, the first fracturing campaign by a western service company took place in Kazakhstan, in the Mangistau Oblast on the shores of the Caspian Sea. In the past, there had been several attempts at fracturing in this area, involving rather primitive methods using diesel and sand, but no significant proppant volumes were placed. In the winter and spring of 2001, a second campaign was completed, following good results from the two wells stimulated in 2000.
This paper is a case study considering 12 fracture treatments applied to ten wells in the Arman Field. The producing reservoir has many complications for fracturing (high clay contents, very heterogeneous layering, high water saturation and significant Gas Oil Ratios (GORs)) and is of moderate permeability. In addition, many of the wells are deviated, which can cause problems due to initiation of multiple fractures. Some of the wells had already been producing for some time, and some of them were fractured immediately after being drilled. There is currently a produced water re-injection scheme in operation to enhance recovery and maintain reservoir pressure.
The goal of hydraulic fracturing in this medium permeability oil reservoir was to bypass skin damage and increase the near-wellbore permeability to reduce the apparent skin effect of high rate multi-phase flow (oil+water+gas) below the bubble point. The wells are being produced with ESP's or rod pumps with a bottomhole flowing pressure below the bubble point. The fracturing was a great success and the oil production was improved by a factor of 2 to 5. In some cases, the increase in production must have also been caused by an increase in the kh of the well, due to fracture growth into a layer which was not previously in communication with the wellbore.
A novel method is presented for improving gas conformance during IOR operations. The process exploits the injected gas phase for carrying the diverting agent to the thief zone, and has the potential to provide a significant improvement over existing water based diverting technology. Laboratory studies and results of an exploratory field test are presented. Studies are underway to design and implement a significantly larger field test.
Miscible gas injection (CO2 or CO2 / light hydrocarbon mixtures) is often exploited as a tertiary IOR mechanism. However, the presence of thief zones, which offer a path of least resistance between injector and producer, results in early gas breakthrough, poor aerial sweep of the injected gas, increased gas recycling costs, and incomplete oil recovery. Consequently, any mechanism that will provide for in-depth reservoir plugging of thief zones will greatly improve the efficiency and economics of gas injection IOR processes. Additionally, the optimal solution to the thief zone plugging problem would be carried by the injected gas phase as the gas has identified the location of the thief zone, and presents the ideal mechanism for carrying the plugging agent to the thief zone.
A novel process which incorporates most of the elements of the optimal solution was investigated for improving aerial sweep during gas injection at Anadarko's NE Purdy Springer Sand Unit (NEPSU). The process calls for dissolving a high viscosity (1 MM cP) polydimethylsiloxane polymer in the flowing gas stream either at the surface or injector conditions. Because the polymer is not directly soluble in the injected gas, a co-solvent is incorporated with the polymer. The type and amount of co-solvent is adjusted to create a mixture that is a stable solution of polymer, co-solvent and injected gas at the injectors. However, the mixture destabilizes at the higher temperature and lower pressure encountered in the reservoir to deliver a viscous polymer phase for plugging1,2. The co-solvents most suitable for this application are light hydrocarbons in the C2 to C20 range or mixtures thereof. Initial laboratory studies investigated both propane and butane as potential co-solvents. Because of its ready availability and higher vapor pressure, the preliminary field test used propane as the co-solvent.
The ideal application of this technology would call for formulating an optimal system such that the polymer/co-solvent mixture is solubilized in the injected IOR gas before the mixture reaches the injectors, but becomes a two phase system at the higher temperature and lower pressure encountered in the reservoir. Preferably, the polymer mixture is injected directly into the surface tubing carrying the IOR gas, and dissolves in the gas at surface conditions. Such an idealized condition is depicted in Figure 1, which plots the surface, injector and reservoir conditions at NEPSU. Also, drawn in is the line identified as the Optimal COP Boundary. COP is the Critical Opalescence Pressure, and is the physically measured pressure at any given temperature where critical opalescence is observed in the polymer solvent mix. All conditions of temperature and pressure above the COP line are single-phase regions and depict completely homogeneous polymer solutions. As the system goes from single phase to two phase, the particles of polymer first make an appearance as sub-micron sized particles capable of scattering light, and it is this effect that gives rise to critical opalescence. All points below the COP line are in the two phase region where a distinct second polymer rich phase is observed.