Secondary Oil Recovery Process Research Articles

A Decline-Analysis Technique Incorporating Corrections for Total Fluid-Rate Changes

Summary Decline analysis inherently assumes a constant total-reservoir-fluid rate in contrast to constantly varying rates in actual field operations. This paper provides an approach for determining decline constants under varying total fluid rates for secondary or tertiary oil recovery processes. It further enables forecasting oil and nonoil production performance under different total fluid rate strategies. The technique helps identify pseudosteady state flow periods when decline analysis techniques are valid. It distinguishes incremental from accelerated oil responses when a recovery process change, operating practices, or workover activity causes a total fluid rate change.

Parachors Based on Modern Physics and Their Uses in IFT Prediction of Reservoir Fluids

SummaryPrediction of interfacial tension (IFT) is essential for modeling many secondary and tertiary oil recovery processes. The parachor method (PM) has been widely used to predict IFT. There has been considerable confusion in the literature concerning the PM for estimating IFT. The confusion is based primarily on the lack of clarity concerning the scaling exponent and parachors derived from this exponent.According to modern physics, the theoretical value ofthe scaling exponent is 3.88 for all pure substances, although several values may be found in the literature, usually altered to match existing data. This paper addresses clarification of the confusion about the scaling exponent, derivation of parachors for pure species occurring in petroleum fluids and oil cuts, and verification of the validity of these derived parachors in IFT prediction of reservoir fluids.We have analyzed experimental data for various compounds occurring in reservoir fluids and found that 3.88 is a valid scaling exponent for pure species inside and outside, to some large extension, of the critical region. Taking 3.88 as a fixed scaling exponent, parachors of 139 crude oil components are back-calculated by means of surface tension and density data obtained from experiments by previous investigators. These parachors are compared with three selected parachor correlations for IFT prediction of six crude oil and CO2 mixtures and are found to be more accurate.

ASPHALTENES ADSORPTION BY QUARTZ AND FELDSPAR

ABSTRACT The adsorption of asphaltenes and resins from toluene solutions onto quartz and feldspar and the effect of this process on the properties of the mineral-aqueous solution interface have been investigated. Asphaltenes were adsorbed to a greater extent than resins, and the adsorption of mixtures was at least equivalente to the weighted average of the adsorption of both components separately. The electrophoretic mobility of quartz or feldspar was not modified by the adsorption of asphaltenes or resins, indicating that the sites responsible for the surface charge of the minerals were unaffected by the presence of the adsorved organic species. The adsorption turned the minerals partially hydrophobic. This effect is more important for asphaltene covered particles which do not immerse in aqueous electrolyte solutions, indicating a contact angle larger than 90a immersion become spontaneous in liquid mixtures (methanol-water, ethanol-water), presenting a surface tension lower than 35 mNm-1. Ethoxylated and ethoxylated-propoxylated surface active agents prevent the adsorption of asphaltenes and resins on the minerals, and this effect increases as the ethoxylated/propoxylated moiety of the surfactant increases. The results indicate that fine particles with adsorbed polar fractions of oil play an important role in the stabilization of the water-in-oil emulsions formed in some secondary oil recovery processes and that ethoxylated/propoxylated surfactants and/or solvents may prevent the formation of these emulsions by modifying the wetting behaviour of the mineral particles.

VISCOMETRIC MEASUREMENT OF CHROMIUM(III)-POLYACRYLAMIDE GELS†

Gelled polymers are being used increasingly to modify the movement of injected fluids in secondary and enhaced oil recovery processes. A common gelation process involves the reduction of Cr(VI) to Cr(III) in the presence of polyacrylamide. The Cr(III) reacts or interacts with the polymer to form a gel network. Although correlations of gelation time with principal process variables have been obtained, viscometric data have not been reported during or after gelation. These data are needed for fluid flow calculations in surface equipment and estimation of flow behaviour in reservoir rocks. A Weissenberg Rheogoniometer, with cone and plate geometry, was used to obtain viscometric data for the gelation of polyacrylamide and chromium (III). Solutions consisting of polyacrylamide polymer, sodium dichromate-dihydrate and sodium bisulfite were gelled under a steady shear field at constant temperature. The shear stress versus time profile for the galation process was interpreted to define a gelation time and to det...

Flow of Oil-in-Water Emulsions Through Tubes and Porous Media

Abstract The flow of oil-in-water macroemulsions through both porous media and capillary tubes has been studied experimentally and described mathematically. Macroemulsions are those emulsions with most of their droplet diameters greater than I AM, which is the same order of magnitude as the pore constrictions. The emulsions were pumped with a positive displacement pump through several porous media and capillary tubes connected in series. The rheological behavior of macroemulsions with oil concentrations ranging from 10 to 70 vol% was obtained using capillary tube data. Emulsions with oil concentrations less than 50% behaved like Newtonian fluids, white those with concentrations greater than 50% behaved like pseudoplastic fluids. Viscoelastic effects were not observed for these fluids. A correlation, which uses both capillary and core flow data, was developed for describing the flow of non-Newtonian macroemulsions through porous media. This led to a general equation that reduced to Darcy's law for Newtonian fluids. The average relative error found when applying the method of correlation was +/- 4 %. Introduction The subject of emulsions is a broad field that includes many instances of application in industry. We are interested mainly in one specific area of application here - the oil industry. The study of emulsions has received considerable attention in petroleum research laboratories during the past 15 petroleum research laboratories during the past 15 years. The development of new methods of secondary recovery and the potential application of crude oil transportation through pipelines as stable emulsions have increased the number of research programs dealing with emulsions. programs dealing with emulsions. Macroemulsions, or ordinary emulsions, are dispersions of one liquid within another liquid. third component in an emulsion is the emulsifying agent or emulsifier, which has two principal functions:to decrease the interfacial tension between the liquids, thereby enabling easier formation of the greatly extended interface, andto stabilize the dispersed phase against coalescence once it is formed. With water or brine as one of the liquids, two types of emulsions are possible - oil-in-water (O/W) and water-in-oil (W/O) emulsions. Note that most of worlds's crude oil is produced in emulsion form. These emulsions are generally water-in-crude oil emulsions, which are more viscous than either of their constituents. Since we are interested only in maximum economical oil production, it is a common practice to separate emulsions production, it is a common practice to separate emulsions into their components, thereby obtaining reduced viscosity. This is accomplished in the oil field by using chemical and heat treatments. In contrast to W/O emulsions, O/W emulsions have lower viscosities than their oil constituent. This was considered by some investigators during the development of systems for producing and transporting crude oil as O/W emulsions. During the last decade or so, a number of new secondary oil recovery processes have been developed. These methods include the use of high-viscosity emulsions to displace oil, the use of emulsion slugs between the displacing fluid (water) and the displaced fluid (Oil), and controlled viscosity microemulsions. We see that, for an engineer to describe properly the flow behavior of emulsions in both pipelines and reservoirs, he must know the properties of emulsions and the physical laws properties of emulsions and the physical laws controlling their flow through tubes and porous media. The purpose of this research was to study the flow of O/W macroemulsions through both porous media and capillary tubes. The rheological characteristics of emulsions were analyzed by using capillary viscometers. SPEJ P. 369

An Evaluation of Miscible CO2 Flooding in Waterflooded Sandstone Reservoirs

Miscible CO2 flooding in waterflooded sandstone reservoirs was studied using hypothetical reservoirs that incorporated rock and fluid properties representative of many watered-out Mid-Continent reservoirs. A four-component, miscible, mixing-parameter reservoir simulator was used to investigate the factors that govern tertiary oil recovery. Introduction A large number of Mid-Continent and Rocky Mountain sandstone reservoirs are nearing the economic limit of oil production through waterflooding. For these reservoirs, production through waterflooding. For these reservoirs, additional oil production will come from a tertiary oil recovery process, most likely a surfactant flood or a miscible CO2 flood. This paper describes a computer simulation study of the potential of miscible CO2 flooding in waterflooded sandstone reservoirs. The purposes of this study were (1) to determine the expected CO2 tertiary oil recovery under typical reservoir conditions; (2) to determine the best mode of operation - that is, straight CO2 injection or some combination of water and CO2 injection; and (3) to determine the sensitivity of the tertiary oil recovery to variations in reservoir parameters. The hypothetical reservoirs analyzed here were constructed to incorporate rock and fluid properties representative of many nearly watered-out Mid-Continent oil reservoirs. The ranges of rock and fluid properties to which the results of this study apply include porosities from 15 to 25 percent, permeabilities from 30 to 500 md, formation thicknesses from 15 to 40 ft, well spacings of 10 to 40 acres, kV/kH ratios from 0.01 to 1.0, and oil viscosities from 1 to 10 cp. It was assumed in this study that the reservoir was maintained above the miscibility pressure of the reservoir crude oil and CO2. pressure of the reservoir crude oil and CO2. Several papers in the literature describe the past work with CO2 displacement processes and water-solvent mixtures. Rathmell et al. and Shelton and Schneider presented experimental studies of the miscible CO2 process. presented experimental studies of the miscible CO2 process. Caudle and Dyes and Blackwell et al. describe the concepts of displacements using combinations of water and solvent injection. Several authors have discussed field applications of CO2 injection as a secondary oil-recovery process in carbonate reservoirs. Finally, one paper briefly sketches the application of CO2 injection paper briefly sketches the application of CO2 injection to increase recovery from the Little Creek sandstone reservoir. Simulator and Grid Descriptions A four-component, miscible, mixing-parameter reservoir simulator was used to investigate the factors that govern CO2 tertiary oil recovery. This simulator is basically similar to the one described by Todd and Longstaff, but this simulator incorporates the concepts of miscibility pressure, a residual oil saturation to flooding by a miscible fluid, and adsorption of CO2 by the aqueous phase. In our version, the fourth component is miscible with the gas under all conditions and miscible with the oil if certain miscibility criteria are satisfied. A mixing parameter, omega, defined in Ref. 9, must be specified in this model. In this study, omega = 0.8. A theoretical analysis of the basis of this choice is presented in Appendix A. Sormf, the residual oil saturation to the miscible fluid, was 10 percent, a value based on previous studies. The term "potential tertiary oil" used elsewhere in this paper is defined as the difference between the oil remaining in the reservoir at the end of the waterflood and the oil left because of Sormf. JPT P. 1339

Polymer Flow Behaviour As Applied To Enhanced Recovery

Abstract Polymer solution flow behaviour through porous media has been studied at length over the last decade with a view to improve oil recovery. An attempt has been made in this paper to understand the basic flow behaviour mechanisms involved, along with pertinent aspects. Numerous field results are also summarized which reveal how flood success or failure is dependent on reservoir and fluid characteristics. Introduction IT IS A WELL-KNOWN FACT that during the water flooding used in secondary oil recovery processes, water follows the path of least resistance, which eventually results in "fingering" and early water breakthrough into the producers. At this point, the operation becomes uneconomical - yet up to one third or more of oil may remain in place. Enhanced recovery could be achieved by improving the water-oil mobility ratio*, which ensures a more uniform flow pattern, resulting in increased sweep efficiency. Mobility may be controlled by: reducing the oil viscosity (application of heat, gas resaturation and miscible drives); increasing the water viscosity. In this article, only the work dealing with the latter will be discussed. Initially, one alternative considered was the use of materials such as glycerin, sugar or glycols as viscosifiers. However, the amount required to effect an appreciable viscosity increase is so high that their usage is economically prohibitive. Then serious consideration was given to the use of more efficient synthetic water-soluble polymers. Large size of macromolecules suggests that a great amount of energy will be dissipated, so that the Viscosity of solution could be significantly increased even at low polymer concentration. Currently high-molecular-weight polymers are being used in:polymer flooding, where, by increasing the resistance to flow of water relative to that of oil, fingering is reduced;miscible flooding, where the displacing fluid (surfactants) must be prevented from fingering through the miscible fluid (for these processes, control of the mobility of the following aqueous displacement fluid is essential). It should be pointed out, however, that the economical feasibility of using polymers in oil recovery is still being questioned. Furthermore, a major obstacle to the wider use of polymer flooding is the lack of a satisfactory method for predicting the performance of the oil recovery process. Such a difficulty stems from the lack of understanding of the behaviour of polymers flowing through porous media. Essentially, water mobility is reduced in three ways:by virtue of high viscosity at flooding shear rates;by polymer-medium rock interaction;by a combination of (a) and (b). A great number of water-soluble polymers have been used as water mobility agents. In essence, they fall into two groups: synthetic polymers and biopolymers (polysaccharides), the former being further divided into polyelectrolytes (partially hydrolyzed polyacrylamides) and nonionic materials (polyethyl-eneoxides). Effect of Molecular Size Generally speaking, the effectiveness of polymers in terms of oil recovery increases with the molecular size. The determining factor, however, is -the ratio of a macromolecular diameter to a pore opening*.

Reservoir Stability of Polymer Solutions

A study was made of the specific effects of oxygen, oxygen inhibitors, temperature, and water salinity on a commercially available polyacrylamide used in oil recovery. Because oxygen greatly effects solution stability, particular attention was given to oxygen inhibitors, with emphasis on particular attention was given to oxygen inhibitors, with emphasis on sodium hydrosulfite and formaldehyde. For a number of reasons, the latter is found to be more desirable for the purpose. Introduction Adequate mobility control between fluid banks is a significant factor in the successful application of secondary and tertiary oil recovery processes. Reservoir flooding when the mobility of displacing fluids equals or is lower than the mobility of displaced fluids increases recovery efficiency by virtue of improved pattern conformance. pattern conformance. The popularity of water-soluble polymers as mobility-control agents in oil recovery processes has increased significantly in recent years. Polymers are applicable to several recovery processes. In addition, because large quantities of chemical are required to flood developed fields, many polymer manufacturers have directed their efforts toward this substantial potential market. Several chemical companies have acquired extensive technology in the manufacture of water-soluble polymers, but most of them lack expertise in the polymers, but most of them lack expertise in the oil-recovery applications of such products. High-molecular-weight polyacrylamides are widely used in secondary and tertiary recovery. The material used in this study was a partially hydrolyzed polyacrylamide marketed by The Dow Chemical Co. as 700 polyacrylamide marketed by The Dow Chemical Co. as 700 series Pusher. Other companies also are developing or marketing polyacrylamides. Polyacrylamides control mobility in reservoirs by increasing the viscosity of injection water and, more importantly, by reducing the formation permeability. Reservoir residence times are long for polymer solutions, since mobility control must be maintained essentially throughout the flood life of these solutions. Therefore, polymer stability under field conditions becomes important. Specifically, conditions that may degrade polymer solutions injected into a reservoir must be determined and evaluated. This paper describes the results of a laboratory study conducted to determine factors affecting the stability of Dow 700 series Pusher. The paper quantitatively describes the effects of several field conditions on the mobility control capability of this polymer, from the standpoint of both viscosity and polymer, from the standpoint of both viscosity and permeability reduction. Guidelines are developed for permeability reduction. Guidelines are developed for handling solutions of this material, including the proper use of treating agents, so as to enhance performance. Dow 500 series Pusher was evaluated in a manner similar to that described here. This polymer, which is also used in oil-recovery applications, is lower in molecular weight than Pusher 700. The behavior of Pusher 500 was very similar to that of Pusher 700 in laboratory experiments, so specific data Pusher 700 in laboratory experiments, so specific data discussed here are limited to the material having a higher molecular weight. In addition to obtaining bench measurements of solution properties, we also measured the effects of polymer degradation on flow behavior by flooding polymer degradation on flow behavior by flooding reservoir cores. Flow studies verified that the effectiveness of polymer solutions in providing mobility control in reservoir rock may be impaired under conditions encountered in the field. JPT P. 618

Caustic Slug Injection in the Singleton Field

The watered-out portion of this field in Nebraska appeared to be a good candidate for injection with NaOH. The results of the pilot program have been disappointing, however, probably because of poor sweep efficiency and because of deterioration of the caustic slug. Introduction Waterflooding is still the most widely used of all secondary oil recovery processes. Unfortunately, oil recovery by waterflooding is far from complete because of two inherent limitations: no matter how much water may be passed through a reservoir, some quantity of residual oil remains in the pores that have been swept by the injected water; and economic considerations require that waterflooding be terminated when the produced WOR exceeds some critical limit, even through portions of the reservoir may not yet have been swept. Mungan showed that, at breakthrough, oil recovery from oil-wet cores is always less than from water-wet cores and that, after breakthrough, large quantities of oil are produced, accompanied by a high WOR. Leach et al. and Mungan showed that in some cases the oil recovery can be made more efficient by changing the pH of the injected water. We shall discuss here a laboratory study of oil recovery efficiency in synthetic cores using Singleton crude and water of pH ranging from 3.5 to 12.5, and the field trial based on the laboratory findings. Laboratory Study Most of the displacement studies were performed in flow tubes packed with unconsolidated Ottawa sand. Each tube had a cylindrical section 2.062 in. ID and 30 in. long, and was made of monel metal. The inlet flange had a straight face, two entry ports, and the usual fluid distribution grooves. The outlet flange, however, was bored in the shape of a funnel, which was packed with silica flour consisting of a mixture of 325- and 400-mesh powder. This effectively eliminated capillary end effects. The tubes were packed with a sand having a broad particle-size distribution. Experience has shown that if the sand is well sorted in particle size, the resulting unconsolidated pack gives waterflood residual oil saturations that are unreasonably low, ranging from 10 to 15 percent pore volume (PV). A commercially available sand mixture, American Graded Sand Co. AGSCO No. 16 sand, was used to pack the tubes and gave waterflood residuals of about 30 percent PV. The particle-size distribution of this sand is given in Table 1. Much care was devoted to cleaning the sand, and a technique involving no vibration was developed to eliminate segregation of grains of different sizes during packing. Random cores from several packs indicated the porosity and permeability to be uniform. Displacement experiments permeability to be uniform. Displacement experiments were also performed in two 10-ft-long, 4-in.-diameter Berea cores. Formation sensitivity studies were made with small cores from the Singleton field. These cores had been handled and stored in a conventional manner, with no precautions taken to keep them fresh or in their native equilibrium state. The refined oil used - Klearol* - was purified using procedures described elsewhere. JPT P. 1569

Analytical Techniques for Recognizing Water- Sensitive Reservoir Rocks

Abstract The permeability damage that certain reservoir rocks undergo when infiltrated by fresh water is well recognized in the petroleum industry. Two causes of damage, swelling of clays and plugging by rearrangement of indigenous particles, result from inherent properties of some rocks and can be determined by laboratory analysis. The presence, cause and magnitude of water sensitivity in most reservoir rocks can be recognized by a combination of the following techniques: - Single phase permeability measurements with gas and a series of brine of decreasing salinity on extracted core plugs to determine if permeability varies with salinity. - X-ray diffraction analysis to detect swelling clays (montmorillonite, mixed-layer clays and certain types of illite). - Physical swelling tests to determine the actual swelling capacity of indigenous clay minerals. - Microscopic examination of rock thin sections to determine the distribution of clay minerals relative to the pore system. Typical analyses are given for reservoir rocks than are - not sensitive, - water sensitive from swelling clays and - water sensitive from particle plugging. Introduction Reservoir rocks that are susceptible to permeability damage during drilling, completion, stimulation and workover operations are well known in the petroleum industry. Permeability damage around a well bore can prevent the detection of oil zones in a wildcat well or lower productivity of completed wells. In secondary recovery operations, a damaged reservoir may mean the difference between economic success or failure. Research and development work on secondary and tertiary oil recovery processes must consider the susceptibility of a reservoir rock to permeability damage in evaluating the recovery process. A whole host of physical and chemical processes are responsible for reservoir damage. Some types of damage occur because of the particular mineralogical and textural properties of the reservoir rock; other types of damage occur as a result of a particular production operation. The causes of damage that are related to rock properties are:1. swelling of indigenous clays that constrict the pores;2. dispersion of indigenous, non- swelling particles, rearrangement of the particles during fluid flow, and plugging of the pore system; and 3. a combination of swelling and dispersion; slight swelling promotes loosening and mobility of fine particles. Causes of damage that originate from a specific production operation are:1. invasion of solid particles from drilling mud or injected fluids; 2. invasion of solid particles from oil well cementing operations; 3. precipitation of salts from the reservoir brine in the zone of relatively lower pressure around the well bore; 4. water block or emulsion block; 5. direct or indirect effects of bacteria; and6. completion practices not suitable for a specific reservoir. Any porous medium, regardless of its inherent properties, could undergo permeability damage by conditions in the second category. The first category of reservoir damage, however, is possible only in rocks that are inherently water sensitive as a result of their mineralogy and texture. In either case, reservoir damage produces the same symptom: reduced well productivity. Before the damage can be repaired, or before damage to a similar reservoir can be prevented, the cause must be determined. The analytical methods presented in this paper were developed to recognize water sensitive reservoir rocks. The philosophy of developing this type of analysis is as follows. If damage is suspected in a reservoir, core samples can be analyzed for water sensitivity. If the analysis indicates sensitivity, then production operations can perhaps be modified to prevent additional damage. If the results of the analysis indicate no sensitivity, attention can then be focused on the production operations rather than on the reservoir rock.