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Results
Acid Sludge Characterization and Remediation Improve Well Productivity
Wong, T.C. (Chevron Petroleum Technology Co.) | Hwang, R.J. (Chevron Petroleum Technology Co.) | Beaty, D.W. (Chevron Petroleum Technology Co.) | Dolan, J.D. (Chevron U.S.A. Production Co.) | McCarty, R.A. (Chevron U.S.A. Production Co.) | Franzen, A.L. (Chevron U.S.A. Production Co.)
Abstract Many oil wells in the Permian Basin have reported sludging problems associated with acid stimulations. The acid sludge is similar among wells and was identified as a viscous emulsion stabilized by asphaltene-rich organic solids. The sludging tendency of the oil increased with the concentrations of asphaltenes and resins, base number of the oil, and ferric ion content in the acid. Only three out of nine commercial acid systems tested were effective in preventing acid sludge formation; they all utilize the same novel iron control technology, i.e., catalytic reduction of ferric ions. Several commercial and generic solvent systems were effective in dissolving acid sludge, including mixtures of an aromatic solvent (e.g. xylene) with either isopropyl alcohol (2:1 volume ratio) or EGMBE (2:1 to 3:1 volume ratios). Selection of acid formulations and solvent systems was based on cost effectiveness and operation safety. Field implementation proved successful. If the results of this study had been implemented earlier in the lives of some of the Permian Basin properties, the recovery of 574 BOPD of lost or deferred production from 99 wells could have been realized. This would have resulted in an estimated increased revenue of over $3 million in one year. Introduction Various fields in the Permian Basin in West Texas have reported a "sludging" problem associated with acid stimulation. This sludge, more commonly known as "acid sludge," was found to occur in both producer and injector wells in the Permian Basin. In some cases, acid sludge was related to CO2 breakthrough. Samples recovered from all of the above situations appeared to be quite voluminous, viscous, and stable indefinitely. This resulted in a dramatic reduction of oil production or water injection rate in some of the wells. Early studies have revealed that crude oils in many producing areas of the United States and Canada form acid sludge upon contact with acid. The acid sludge potentially plugs pore throats, pores, vugs, wormholes, and natural fractures and produces skin damage which significantly reduces permeability in the near-wellbore region. Acid sludge can cause damage that partially, if not totally, offsets the stimulating benefit of the acid. However, the composition and chemical structure of acid sludge have not been well understood. It has been reported that acid sludge is asphaltenic in nature; can exist in some form of an emulsion, solids, or a mixture of both; and may not dissolve in solvents. Asphaltic components of crude oils, which are generally present in colloidal state, are apparently destabilized by low pH as a result of acid contact.
- North America > United States > Texas (1.00)
- North America > United States > New Mexico (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (23 more...)
- Well Completion > Acidizing (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (0.66)
Abstract A low toxicity polymer crosslinking system has been developed which is tolerant of high brine salinity and hardness and has worked well in two field applications. The system involves the gelation of polyacrylamide with zirconium lactate; this is a lower toxicity system than the commonly used chromium gelling systems. Microgels prepared with the new polyacrylamide/zirconium system have been tested in two different field applications:an injection well test in a large waterflood unit in northeastern Oklahoma, the North Burbank Unit, and an injection well and a production well test in a waterflood unit in northern Texas, the C.B. Long Unit. In the injection well test in the North Burbank Unit, 69,000 barrels of polyacrylamide/zirconium gel were injected into an injection well. Pressure falloff tests before and after polymer gelant injection showed a reduction in fluid mobility by a factor of 5 to 6 as a result of the crosslinked polymer treatment. In the C.B. Long Unit, an injection well was treated with 65,500 barrels of microgel and injection profile surveys before and after the treatment showed a diversion of 55 percent of the injected fluid to a low permeability zone. Several offset producing wells responded to the polyacrylamide/zirconium treatment and incremental oil production has been in the range of 15 to 20 BOPD. The production well treatment in the C.B. Long Unit resulted in a reduction of the producing water-oil ratio. This low toxicity polymer crosslinking system has been developed for in-depth diversion of injection fluid in a variety of applications. The polymer gelant uses a fairly low concentration of polymer and zirconium crosslinker so large volume treatments are economical. The polymer system is also tolerant to hard brines and low pH environments. Introduction Polymer and gelled polymer solutions have been used since the 1960's to improve waterflood sweep efficiency and to increase the macroscopic displacement efficiency of water displacing oil. Some gelled polymer solutions used for these purposes, however, had drawbacks associated with their use. These drawbacks included a requirement for fresh or softened water and/or the use of chromium (+6), a carcinogen, as a crosslinker. This paper reports on the development of a low toxicity, polymer crosslinking system which is tolerant to high salinity and hardness in the water used as the polymer solvent. The newly developed polymer crosslinking system is also effective at low polymer concentrations which makes large volume treatments economical. Zirconium (IV) Lactate as a Low Toxicity Crosslinker Due to concerns over the environmental effects of chromium crosslinkers, zirconium (IV) and titanium (IV) complexes were evaluated as alternative crosslinkers for gelation of polyacrylamide. Extensive tests showed that polyacrylamide when crosslinked with zirconium and titanium produced stable gels in high salinity brines. Water analyses for two of the produced brines used in this study are shown in Table 1. Although a number of titanium and zirconium crosslinkers were identified which can produce stable gels in high salinity brines, our discussion in this paper will be limited to the data presented in Table 2 and references 1 through 3 show that zirconium (IV) lactate is a low toxicity compound which is a mild eye irritant and slight skin irritant to animals.
- North America > United States > Oklahoma (0.68)
- North America > United States > Texas (0.67)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
Abstract This paper addresses mathematical modeling of free-fall gravity drainage which is believed to occur in naturally fractured reservoirs after depletion of oil in the fractures or gas injection into the fractured system. Comparison of wetting phase recoveries calculated using existing mathematical models with experimental data indicates the inaccuracy of these models. The causes of error are identified to be the unrealistic assumptions made in formulation of the models. Based on Darcy's law and film flow theory, we have developed a new mathematical model to describe the free-fall gravity drainage process. A simple non-linear governing equation for phase demarcator in dimensionless form was formulated and solved numerically as a function of dimensionless time. Based on the dimensionless demarcator, fluid recovery during free-fall gravity drainage is calculated. Comparisons of wetting phase recoveries given by the new model with 20 sets of experimental data obtained under thermodynamic equilibrium conditions for a variety of fluids and cores show much better accuracy of the model over the existing models. Using the dimensionless time, tD = ke gt/ L, fluid recovery obtained from laboratory studies can be scaled to field applications for estimation of projected oil recoveries in oil fields. We have also applied the new model to simulation of free-fall gravity drainage under non-equilibrium conditions where molecular diffusion between phases is considered. Experimental oil recovery data obtained from CO2 injection into a Berea core and a reservoir sandstone core, which were saturated with separator oil, have been matched by the model using empirical correlations for fluid properties. The objective of this paper is to provide reservoir engineers with a useful tool for estimating the oil recovery from fractured reservoirs after gas injection. Introduction Because fractures are highly conductive to gas and gas is the nonwetting phase in the rock matrix, gas injection into fractured reservoirs has been traditionally considered as an inefficient method for enhancing oil recovery from fractured reservoirs. However, the Midale Pilot indicated that the efficiency of CO2 injection into fractured reservoirs is not as low as expected. The only explanation is that when a non-equilibrium gas is injected into the fractured system at elevated pressure, compositional effects become active between the gas in the fractures and oil in the matrix. Due to multi-contact mechanism, light hydrocarbons in the oil can be extracted from the virgin oil bank forming a "gas" -rich light liquid phase and an oil-rich heavy liquid phase. This kind of phase split has been reported by several investigators including Lansangan and Smith. The interfacial tension (IFT) between phases is low compared to that between virgin oil phase and gas phase. Therefore, the capillary pressure threshold may be overcome by gravity resulting in gravity drainage of the light oil from the matrix blocks. In order to understand the mechanism of gravity drainage and predict the response of fractured reservoirs to gas injection, a mathematical model of the process is desirable. Equilibrium Gravity Drainage. Studies on gravity drainage were conducted a century ago when King investigated the principles and conditions of aquifer motion. Investigations of gravity drainage of oil in oil reservoirs were initiated in early 40's of this century. Leverett and Katz presented data and discussed the theory relating capillary and gravitational forces acting on liquids contained in a sand body. Stahl et al. conducted experiments to investigate behavior of free-fall gravity drainage of water and oil in an unconsolidated sand. Elkins et al. presented a simplified theory of regional drainage of oil from upstructure location to downstructure location due to gravity assuming zero capillary pressure gradient. Cardwell and Parsons presented a governing equation for the free-fall gravity drainage process. They could not solve the equation because of its non-linearity. P. 23
- Europe (1.00)
- North America > United States > Texas (0.69)
- North America > United States > California (0.46)
Abstract Early breakthrough and poor sweep efficiency are common problems in CO2 floods. These problems result from the large viscosity contrast between the displaced and injected fluids as well as from the heterogeneity of reservoir rock. Evidence shows the presence of an aqueous surfactant solution will produce a foam with CO2, which not only controls the gas mobility but may also selectively reduce the gas mobility through regions of differing permeabilities. Experiments were conducted to test the CO2-foam behavior in composite parallel core samples where the two permeability regions are in capillary contact. These composite cores are more characteristic of reservoir conditions. This paper examined the effect of heterogeneity on CO2-foam in composite cores contained coaxial zones of high and low permeability. The results from these experiments indicate that the CO2 breakthrough was delayed in the high permeability region during the transient period when surfactant solutions were used. Without surfactant the flowing quality (fraction of CO2 in total injected fluid) was lower in the low permeability region as compared with that in the high permeability region. These results indicated the favorable fluid mobility in heterogeneous core samples when foaming agents were used. Introduction The occurrence of selective mobility reduction (SMR), by which the mobility of CO2-foam is reduced more in the higher permeability cores than that in the lower permeability cores, was observed in earlier laboratory experiments conducted in individual cores of relatively uniform permeability, with some surfactants. The existence of SMR is also reported by others in the foam literature. For full verification, though the SMR effects needed to be examined in a heterogeneous media where both high and low permeability regions were present and in capillary contact, as they are in different portions of a heterogeneous reservoir. Nonuniformities of the displacement front (in CO2 or any gas flooding process) are often caused by the heterogeneity of the reservoir formation. They result in channeling and early breakthrough, which in turn reduce the sweep efficiency substantially. The use of CO2-foam as a displacement fluid has the potential to reduce the irregularities of the displacement front in a heterogeneous rock, which is often intensified in CO2 flooding due to the viscosity contrast between the two fluids. The experiments conducted in individual cores of uniform permeability could not provide enough information upon which the effectiveness of CO2-foam in reducing CQ channeling and preferential flow could be conclusively evaluated.
- North America > United States > Texas (0.47)
- North America > United States > New Mexico (0.28)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
Abstract CO2-foam has been long realized as an effective mobility reducing agent for CO2 flooding in oil recovery process. Recent researches indicate that some CO2- foams also show an exciting additional characteristic, selective mobility reduction (SMR), in which the mobility of foam is reduced by a greater fraction in high than in low permeability cores in laboratory experiments. Examples of such an unusual property are presented first in this paper to show the mobility dependence of CO2-foams on the rock permeabilities ranging from 30 to 900 md. Secondly, a simple modeling procedure is introduced to evaluate the benefits of using an SMR displacing agent in a typical oil recovery process. In this model, the mobility of the displacing fluid is considered to be proportional to the permeabilities raised to a specific exponent. This allows us, for different values of exponent from zero to one, to examine how different degrees of SMR will affect the oil recovery. The modeling results show that, as expected, the breakthrough time of the faster (higher permeability) layer is delayed and the vertical sweep efficiency of the model is improved if the mobility of the injected fluid is reduced. Furthermore, this improvement becomes even more significant when an SMR fluid is used for the displacement. Even a slightly favorable SMR fluid, that shows a slight dependence of mobility on rock permeability, can significantly reduce the number of pore volumes required to achieve the same degree of recovery as that realized with an ordinary mobility reducing agent.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
SPE 35167 Integrated Geologic, Engineering, and Financial Assessment of Gas Displacement Recovery in Texas D.K. Beike and M.H. Holtz, SPE, Bureau of Economic Geology, The University of Texas at Austin Copyright 1996, Society of Petroleum Engineers, Inc. Abstract A total of 57 commercially viable gas-displacement projects in Texas are classified into seven depositional environments. We collected reservoir and petrophysical data and depth and oil gravity for each reservoir, which gave us a generalized case model for each depositional environment. We also collected and analyzed information about the design of these projects, concentrating on pattern, spacing, and production processes previously applied. Cost calculations that are presented are in accordance with a previous cost study by Beike and Holtz. Finances were analyzed for the case model of each depositional system according to net present value and internal rate of return. We also used an economic sensitivity analysis to investigate the effect of oil price, well spacing, and incremental recovery. The potential for reserve additions from CO2 flooding in Texas is substantial. An additional 1,730 reservoirs are candidates for gas-displacement recovery. This set of reservoirs contains 70 BSTB of original oil in place, 23 BSTB of mobile oil, and 37 BSTB of residual oil. Factoring in a conservative reserve-growth recovery of an additional 10 percent of original oil in place, we estimate that future GDR projects could produce 7 BSTB in Texas. Most of this reserve growth will continue to come from restricted- to open-platform carbonate reservoirs in West Texas. Introduction and Objective A large volume of oil remains in existing Texas reservoirs (Fig. 1). Cumulative production to date represents approximately 25 percent of the original oil in place (OOIP), whereas a full 33 percent of the OOIP is remaining mobile oil and 37 percent is residual oil. Capturing this significant residual oil resource will require detailed reservoir characterization and application of enhanced oil recovery methods. Over the last 20 yr much information has been gained from individual enhanced oil recovery (EOR) projects, most of which involved gas-displacement recovery (GDR). Such information invites integrated geologic-engineering-financial analysis of the projects that were commercially successful. Because economic-viability influences can be determined by means of this analysis, estimation of up-front capital costs can be made more accurately. These estimates in turn will lead to a possibility of increasing production of oil in mature Texas reservoirs. Our objective was threefold:We began by determining characteristics of reservoirs in which GDR had been successfully applied. All geologic, engineering, regulatory, and economic characteristics were included. We analyzed the effect of GDR as an EOR method by examining production characteristics, incremental production, and recovery efficiency. We used the historical information to model the economic viability of GDR, in order to delineate the resource potential and sensitivity of additional oil production to salient influences. GDR projects characterized were those that were implemented beyond the pilot stage. components of the GDR ProductIon EnvIronment Essentially four components form the flamework of possible EOR production. The first is EOR process technology, the GDR of which is analyzed herein, and which in turn is determined by geological environment, petrophysical parameters, and costs. The second component is macroeconomic environment, which is influenced by existing industry strength, import rate, and world oil production. P. 227
- Geology > Rock Type > Sedimentary Rock (0.98)
- Geology > Sedimentary Geology > Depositional Environment > Marine Environment (0.69)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (23 more...)
Abstract Past production results after acidizing treatments on oil and gas wells have been unsatisfactory in many areas due to the use of conventional acid mixtures along with inadequate lab testing and design procedures. This paper presents a means of acid-oil emulsion and sludge testing analogous to downhole conditions which appears to be a key element to effective acidizing designs. This study produces improved techniques for testing, design, quality control, and evaluation of such treatments. Production results authenticate the success of these advanced quality control and design measures. Introduction Acidizing existing and new wells with carbonate and some sandstone formations is a common and necessary treatment to maintain commercially productive and profitable wells. Acid is pumped into the subterranean formation to increase the pore spaces by etching the rock as it passes through and dissolving particles plugging these spaces thus increasing production. Many reservoirs in areas such as the Permian Basin of West Texas, have produced many of the "light end" crudes and currently produce crudes which predominantly contain "heavy ends" (asphaltenes, paraffin, etc.) As acid and oil mix together during stimulation treatments, emulsions and sludging can occur which damage pore spaces and detract from production. These problems are detrimental under normal circumstances. However, they dramatically increase as the asphaltene/paraffin content of the produced crude increases along with the addition of both ferrous (Fe2+) and ferric (Fe3+) iron in the acid. Iron in acid can originate from several sources such as contamination in the acid solution itself, leaching from the iron-containing piping and surface pumps, as well as from formation rock and fluids. Also, the additional effects of lower bottomhole temperature or pressure detracts from cleanup operations. All of the aforementioned can contribute to emulsions and sludges, and dramatically reduce the potential production from a formation resulting in well failures. This paper presents a state-of-the-art testing technique which is similar to downhole conditions and unlike standard acid-oil emulsion tests performed in the past. P. 641^
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
Abstract With improved gas pricing the Morrow and the Atoka formations of S.E. New Mexico are seeing substantial amounts of renewed activity. The paper presents background information such as lithology, formation properties obtained from X-Ray Diffraction and SEM Analysis and rock properties obtained from other sources. Casing and perforating programs along with completion and stimulation practices are also discussed. The paper lays emphasis on the recent use of the Binary Foam as a fracturing fluid along with case studies. Additionally, the paper goes over the design of a Binary foam frac with the aid of 3-D design model and foam fluid rheology. Post frac productivity results along with the amount of proppant placed in the fracture are presented to help in future frac designs. Introduction The Morrow and the Atoka sands are deposited erratically on the Northwestern shelf of the Delaware Basin. The predominantly higher productivity wells are in western one-third of Lea County and almost all of Eddy County, New Mexico. See the map in Figure 1. Reserves in the Morrow formation in S.E. New Mexico which covers approximately 4.0 million acres, have been estimated to be in excess of 10 trillion cubic feet of gas and about 100 million bbl of oil and/or condensate. Completion results are from fair to highly successful in older fields which are being expanded and newer fracturing techniques are stimulating older depleted zones into higher productivity. With increase in gas prices, and a greater demand for a cleaner burning fuel since late 1980s, there has been a surge in Morrow and Atoka drilling activity. An additional incentive for Morrow and Atoka wells is the possibility for more oil and gas production from the Strawn, the Wolfcamp and the Bonespring formations. Completion difficulties encountered in the Morrow and the Atoka have resulted in lower productivity and in some instances even forced abandonment of several promising prospects. Where improper and untried completion practices have been used, the production test results have been substantially inferior to offset wells and DST information. Up to late 1960s. the only Morrow production in S.E. New Mexico was from wells completed natural. The same was mostly true of the Atoka production. Stimulation when attempted consisted of gelled oil or saturated NaCl brine based hydraulic fracturing. P. 589^
- North America > United States > New Mexico > Lea County (0.34)
- North America > United States > New Mexico > Eddy County (0.24)
- Research Report > New Finding (0.46)
- Overview > Innovation (0.41)
- Geology > Mineral > Silicate > Phyllosilicate (0.48)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.46)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (27 more...)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Well Completion > Completion Installation and Operations > Perforating (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Introduction We performed intense quality control (IQC) on 54 hydraulic fracture treatments during 1992-93. Our detailed fluid testing in the field has indicated (he complex nature of fracture fluid systems currently used by the industry. This paper documents our experience with fracture fluids blended in the field and tested under in-situ conditions. Several problems were encountered while performing intense quality control operations on these wells. including overcrosslinked gel systems and contaminated additives. Many of these problems became apparent only after evaluating the fracture fluids at bottomhole temperatures and shear rates. Many fluids that failed viscosity tests at bottomhole conditions looked to be adequate when tested at surface conditions. The importance of quality control in stimulation operations has been investigated and its importance recognized by the industry. Intense quality control is performed on location using equipment carried in a rheology van. The rheology van contains two Fann Model 50 viscometers that we use to evaluate the fracture fluids at bottom hole temperatures and shear rates. and a complete wet chemistry lab. Analyses of fracture fluids with the rheology van has been described ill a previous paper and GRI publication. Intense quality control is not a new concept. IQC is routinely used in the evaluation of cement slurries. To test recommended mixtures of cement and additives, pilot tests are always performed on cement slurries prior to pumping to test recommended mixtures of cement and additives. Results of the pilot and blend tests indicate if a particular cement mixture will perform as designed. Similarly, we test fracture fluid systems at conditions designed to simulate reservoir temperatures in our IQC work. We use the chemicals and additives that will actually be pumped during the treatment. Using the actual chemicals is a critical part of IQC, and it is the reason that testing must be performed at the wellsite, prior to the treatment. Blended samples arc collected during the fracture treatment and tested as the treatment is in progress. The tests performed during the treatment are compared to the pilot tests to ensure the fluid pumped down hole is performing as expected. We inventory all additives before. during, and after the treatment to verify the fracture fluid system is blended accurately. Often, the success of a stimulation treatment is incorrectly judged by the amount of fluid and proppant left over at the end of the treatment. If the viscous fluid properties of the fluid pumped during the treatment are measurably different than those used to design the treatment. then it is likely that the propped fracture geometry will also differ. For example, a low viscosity fluid system with poor proppant transport properties will allow proppant to settle into the bottom of the fracture, reducing the amount of proppant placed across the pay interval, potentially reducing fracture length and fracture conductivity. A fracture fluid that is too viscous can create a wide fracture, thus reducing the propped fracture length. If the fluid is too viscous, the amount of time for the fracture to "clean up" will increase, especially if the fluid does not break properly. Two SPE publications clearly show the problems one can have if the fracture fluid does not break. Poor cleanup can significantly reduce profit from the fracture treatment. Due to the complex nature of fracture fluids, it has been well documented that the apparent viscosity can be a strong function of the testing procedures. P. 631^
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
Abstract This paper presents the results of laboratory foam tests that will be used to determine foam parameters for use in foam-flood reservoir simulators. Foam tests were performed at average reservoir conditions of 101 F and 2100 psig with EVGSAU cores. Foam was generated in situ by simultaneous injection of surfactant solution and CO2 into a brine-saturated core. In this study, the gas-liquid volumetric injection ratios of 2, 4, and 6 (with foam qualities of 66.7%, 80.0%, and 85.7%, respectively) were examined. The flow rate in terms of total interstitial velocity varied from 0.36 to 34.38 ft/day. The surfactant was tested at concentrations of 1000 and 2500 ppm active. The resistance factor of each test ranged from 3 to 63, indicating that foam was generated at all the testing conditions. Brine permeability, which changed after each foam test, had a significant effect on the calculation of foam apparent viscosity. Because of varying brine permeability, the resistance factor data is more suitable for simulator input than the apparent viscosity data. Introduction The East Vacuum Grayburg San Andres Unit (EVGSAU), located in Lea County, New Mexico, and operated by Phillips Petroleum, is the site selected for a comprehensive evaluation of the use of foam for improving the sweep efficiency of a CO2 flood. In this four-year project, reservoir simulation studies are involved to develop a field-scale foam-flood simulator and to predict foam flood performance in the pilot. Our goal is to determine foam parameters to be used in the foam-flood simulator. Further, quantitative information on foam-flow behavior at various reservoir flow rates, injection ratios, and surfactant concentrations is required as input to foam modeling. The approach of most foam modeling, to date has been either to use mechanistic modeling or to abandon mechanistic modeling. In the latter approach, there are empirical expressions for gas-foam mobility as a function of flow rate, gas fraction, surfactant concentration, and other factors. The parameters associated with these empirical expressions are obtained from various foam tests. However, these expressions make no explicit reference to foam texture or foam bubble size, even though foam texture controls gas-foam mobility. In the former approach, a population balance model is used to allow the effect of foam texture to be directly incorporated into the expression for gas-foam mobility. This balance model accounts for changes in foam texture caused by mechanisms which create, destroy, or transfer foam as well as foam trapping and mobilization. However, the model parameters of the functional forms chosen for each mechanism need to be fitted to coreflood data from foam tests. Foam is used to improve the volumetric sweep efficiency of gas floods by reducing the gas mobility. However, such a benefit may never be realized if foam cannot be formed under reservoir conditions Some studies reported in the literature indicate the existence of a critical velocity or minimum pressure gradient for the onset of foam generation. P. 483^
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (28 more...)