Fosterton Northwest Unit has undergone 18 years of in-situ air combustion under both dry and wet combustion modes. oil recovery by tertiary wet combustion has been more successful than dry combustion, and a portion of the Unit's oil production is considered to be incremental. Evaluation of the combustion process is currently being hampered by operational problems such as pumping and corrosion.
The Fosterton Northwest (N.W.) Unit* is situated in the Fosterton Field approximately 30 miles northwest of Swift Current, Saskatchewan, Canada, as shown on the map in Figure 1. This paper reviews the performance of the tertiary combustion recovery pilot with emphasis on the period from January l, 1974 to October 31, 1987. Performance prior to January l, 1974 has been discussed previously in the literature.
The pay zone of interest is the Fosterton N.W. Roseray Sand Pool, which has an average net pay of 8.4 m (28 ft), a porosity of 28.8%, and a permeability of 958 md. The oil has a viscosity of 16 cp at initial reservoir conditions and a gravity of 24 API at 52C (126F).
The Unit underwent five years of primary production. followed by 12 years of waterflood recovery, after which 23.2% of the original oil-in-place (OOIP) had been recovered. The recovery scheme was converted to an in-situ dry combustion in 1970 for the purpose of determining the economic and technical viability of the process for tertiary recovery from similar watered-out Roseray Sands in the area.
Since February 1970, the Unit has undergone eight years of dry combustion, followed by ten years of wet combustion. The wet combustion phase consisted of five years of cyclic air-water injection. followed by five years of continuous air-water injection into twin wells. A second burn was ignited in 1984 to increase injection rates and accelerate the in-situ wet combustion process. Replacement production facilities which were built in 1984 have been successful in treating the fireflood type emulsions. The Fosterton N.W. Unit currently has four injectors and six producers, as shown on the map in Figure 2. The project appears to be producing incremental oil, however, fluid productivity has been seriously restricted by pumping problems associated with sand production, high gas production rates, and severe corrosion of the well tubulars.
Fosterton N.W. Unit contains the Fosterton Northwest Roseray Sand Pool, one of two pools in the Fosterton Field. It is situated in Township 17, Range 18 West of the Third Meridian. The Northwest Roseray Sand Pool is small and confined with a moderately thick and uniform sand thickness. A net oil pay map is shown in Figure 2, and an east-west cross-section is shown in Figure 3. The second pool in the field, the Fosterton Main Roseray Sand Pool, is being water-flooded and is not in communication with the Northwest Sand Pool. Both pools are underlain by the Lower Vanguard shale and overlain by a competent shale caprock. The Northwest Pool is a combination structural and stratigraphic trap. The Roseray shales out on all sides forming the trap.
* Unit Ownership: Mobil Oil Canada, Ltd. (50%); Unocal Canada Ltd. (30%); Saskatchewan Oil and Gas Corporation (20%).
This paper describes the industrial pilot results of foam flooding for enhanced oil recovery. The results are explained by the laboratory results obtained. Based on the experiences of the single well foam-flooding results on the Lao Jun Miao field in northwestern China. an industrial pilot foam-flooding operation was carried out in the middle of the reservoir in this field in October 1979. This pilot operation involved IS production wells and 8 injection wells. The area of the pilot operation was 1.23 km. A response was obtained from a small number of the production wells. but no response was obtained from the other wells even two years later To analyze and explain the above-mentioned pilot results. the laboratory experiments were performed. The laboratory conditions were the same as those in the industrial pilot operation. The core sample was divided into two parts. One was swept by the conventional method. and the other was remained under its natural conditions. It was found that the precipitation occurred between the foaming agent and the water injected before the solution formed by foam with air. The amount of the precipitation depends on the concentration of the foaming agent and the salinity. The solubility of the foaming agent can be improved by adding SP-3 to the solution. The dispersion coefficient of the foaming agent (K,) between the crude oil and the formation water was equal to 1.5 in the presence of three phases. The K between the solid and the liquid present in four phases was greater than K. The adsorption isotherm of the foaming agent did not correspond to that of Langmuir's model. It had a maximum value at the critical micelle concentration (C.M.C). The adsorption decreased in the presence of SP-3 and SP-6 in the foam solution.
In principle it was found that the foam was no longer formed farther than 10 meters from the injection well.
The last part of this paper describes the results of simulation using a mathematical model. They correspond to the results of the industrial pilot and the laboratory results.
The formation L, in Lao-Jun-Miao oil field located in Gansu (province), north-west of China, has been developed since 1939. So far 35% of the original oil in place (OOIP) have been produced The total percentage of water cut is 87%. The oil production decreased year by year. In order to increase the volumetic sweep efficiency, increase the total production, and enhance the oil recovery, according to the experiences performed in the single well test, a foam flooding field test in commercial extent at the middle limb in the eastern region of the oil field started in October 1979. In the pilot area, there were 8 injective wells and 18 production wells, it is an irregular five-spot pattern and the trapping area is 89 hectares (Fig.1). The depth of the oil-bearing formation is 670 m. The average effective pay thickness is 4.9 m. The average porosity is 20% and the average permeability is 1310 Sd. The original oil saturation is 84%, and the temperature of the oil-bearing formation is 28C. The 50.5% of the OOIP had been withdrawn before the test.
The reservoir rock is the slightly cemented fine sandstone. The clay content is about 13.3%. It had been obtained by x-ray diffraction analysis that the clay contains dominantly the montmorillonite with the content of 51.30. Then it contains in turn 33% of illite, 12.3% of kaolinite, and 3.4% of chlorite (Tab.1). It had been identified by scanning electron microscopic analysis that the clay cement is in pore-filling form, and the montorillonite covered the surface of the grains in streching form. The composition of the rock grain is shown (Tab.2). The content larger than 80 meshes in diameter is about 74%.
A substantial increase in oil production resulting from CO2 flooding has been clearly identified in two multi-pattern areas of the SACROC Unit. Analysis of the two areas permitted the identification of oil response to CO2 injection with greater accuracy than has previously been possible at SACROC. The areas include the 600 acre [2.43 x 10 (6) m2] Four Pattern Area (4PA) and the 2700 acre [10.93 x 10 (6) m2) Seventeen Pattern Area (17PA). Located in the Kelly-Snyder Field of Scurry County, Texas, the 50,000 acre [202.3 x 10 (6) m2] SACROC Unit is the world's largest CO2 miscible flooding project.
The 4PA encompasses 24 wells arranged in four contiguous inverted 9-spot injection patterns. The area has been on pattern waterflood since 1972 and was at a 95 percent producing water cut when CO2 water-alternating-gas (WAG) injection was commenced in June 1981. An approximate 30% hydrocarbon pore volume (HPV) of CO2 was injected over a 5-year period at WAG ratios ranging from two to eight. CO2 injection ceased in May 1986 and the area has been on continuous water injection since that time. Incremental oil recovery attributable to CO2 injection is estimated currently to be at least 9% of the original oil in place (OOIP). This represents an estimated cumulative CO2 utilization of 9.5 Mft3 per barrel of incremental oil [1692 m3/m3].
Also on pattern waterflood since the early seventies, the Seventeen Pattern Area has exhibited an approximate 5% OOIP recovery after injecting 17% cumulative HPV CO2. CO2-WAG flooding in the 17PA began in May 1981. Currently, the cumulative CO2 utilization is estimated to be 9.7 Mft3 per barrel of incremental oil [1728 m3/m3].
This paper examines the methods used to determine CO2 mobilized oil response, describes how the effects of workovers and other "normal" field operations were accounted for, and evaluates the influence of activities in patterns adjacent to the study areas.
A substantial increase in oil production resulting from CO2 flooding has been clearly identified in two multi-pattern areas of the SACROC Unit. The intent of this paper is to document that response. CO2 performance reported herein is that which has been observed under "normal" field conditions and operations.
SACROC DESCRIPTION AND EARLY PROJECT PERFORMANCE
The SACROC Unit has been the subject of a great many papers dealing with the reservoir description, the CO2 displacement process, CO2 transmission, performance of the CO2 project, and many other topics. The history provided below, therefore, is only a synopsis.
Early History of the Kelly-Snyder Field
Discovered in 1948, the Kelly-Snyder Field is located in Scurry County, Texas (Fig. 1). The discovery well, Standard of Texas Brown 2-#1, was drilled to 6,700 feet [2042 m], 9 miles [14.5 km] northwest of Snyder, Texas. The well flowed 530 bbl/D [84.3 m3/d] from the Canyon Reef formation. Further development drilling proved up an area encompassing some 84,000 acres [340 x 10 (6) m2]. To date this discovery represents one of the last billion-plus barrel reservoirs to be found within the continental U.S.A. Pertinent reservoir data and properties are summarized in Table 1.
The Reagan reservoir of the Sleepy Hollow Field in Red Willow County, Nebraska is an ideal polymer flood candidate. It has viscous oil in a high permeability sandstone with high oil saturation and fresh water available for injection. Laboratory and field testing were used to evaluate emulsion polyacrylamide polymers for injection. Laboratory core tests were of marginal use due to the lack of representative core samples. Fractional flow analysis was used as a screening tool and reservoir simulation studies were used to predict polymer flood performance. A field injectivity test showed the polymer to have much more effect in the reservoir than in the core tests. Based on these results, and a concern that injectivity loss could be excessive, a conservative selection was made of polymer molecular weight and solution viscosity. The polymer flood was initiated on February 14, 1985. An extensive quality control program was implemented to insure compliance of bulk emulsion shipments with specifications and to insure that fluids leaving the mixing plant and throughout the system were of suitable properties. Injected fluid properties were maintained within close tolerances and this effort contributed to the low loss in injection rate experienced in the flood. Swab-back sampling and pressure transient tests were used to measure the properties of injected fluids in the reservoir and to confirm that shear degradation losses at the sand face were not excessive. Water-oil ratios have declined from 45 to 17 in the polymer flood area, which contains 10 injectors and 45 producers. Polymer breakthrough has not been excessive and no emulsion problems have been encountered in the produced fluid system. Corrosion has increased since polymer breakthrough and there is indication of partial plugging of producing wells. Beginning in 1986, due to the downturn in oil prices, efforts were made to lower operating expenses by reducing injection rates and polymer concentration. These changes have significantly reduced operating expenses and have consequently enhanced the economics of the flood. Results to date indicate the flood will be a technical and economic success.
The Sleepy Hollow Reagan Unit, located in Red Willow County, Nebraska, was discovered in 1960 and by late 1962 field development on 40 acre spacing was completed with 157 wells (Figure 1). Primary production continued until the field was unitized to begin peripheral waterflooding during 1966 (Figure 2). Conversion of interior wells to 10 inverted nine spot waterflood patterns occurred in May, 1983 and polymer injection began on February 14, 1985.
Sleepy Hollow consists of a northeast-southwest trending anticlinal structure located on the Southwest flank of the Cambridge Arch, a structural high extending from Nebraska to Oklahoma. Productive area encompasses nearly 10,000 acres with a maximum relief of 40 feet. The Cambrian age Reagan sandstone was formed by the reworking and redeposition of the basement granite wash by longshore currents. It is an unconsolidated, well sorted, homogeneous sandstone containing almost pure quartz, with very little mineral content that might be water sensitive. Reservoir rock characteristics for the Reagan are shown in Table 1.
Oil in the Reagan formation is believed to be stratified into two zones. The upper light oil zone is underlain by an oil mat termed the heavy oil zone. The light oil has a gravity of 31API and viscosity of 24 cp, and is thought to be responsible for nearly all of the Reagan production. The heavy oil has a gravity of approximately 23API and a viscosity ranging from 72 cp to 10,000 cp.
Oil displacement experiments are reported which were performed in stratified rectilinear systems consisting of two lower permeability sandstone slabs, enclosing a central high permeability layer made of unconsolidated glass ballotini. The adjacent layers were in good flow communication, except for a very small region close to the outlet. This arrangement allows the crossflow mechanisms that occur when the viscosity of the displacing brine is increased by adding a water soluble polymer. These mechanisms cannot be assessed by performing experiments in one-dimensional cores or packs. Results of oil displacement experiments are presented for different mobility driving fluids, in which glycerol is used to viscosify the aqueous phase. carbon-I 4 and chlorine are used as radioactive tracers in the experiments. The effluent fluids from each layer were collected and analysed to produce data on the cumulative oil recovery, watercuts, flow rates in each layer, viscosities and concentrations of radioactive tracers.
The results of these oil displacement experiments were modelled using computer simulation, and a very good match to the experiments was obtained. This simulation work confirms the flow mechanisms involved when water soluble polymers are used to increase the oil production from stratified reservoirs.
In stratified reservoirs with high permeability contrasts between layers, early water breakthrough can occur during a waterflood, causing low vertical sweep efficiencies. The use of water soluble polymers to increase the water viscosity has been shown to be an effective way of improving the sweep efficiency and hence increasing the oil recovery. Earlier theoretical work has shown that the mechanism of increasing the recovery of oil in this way involves the crossflow of fluids between the various layers, as well as increasing the velocities in the lower permeability layers adjacent to the high viscosity polymer solution).
A large number of papers have been published which investigate oil displacement using polymer solution in one-dimensional cores. Some experiments have also been performed in two-dimensional systems, but most of these used multiple radial or linear cores in parallel, with no contact between the cores except at the inlet. In the early literature, waterflooding experiments in communicating layered systems were reported, generally from the viewpoint of investigating scaling laws, or recovery mechanisms. More recently, polymer displacement experiments have been performed in stratified systems, with crossflow between layers. Whilst these have provided valuable information on the displacement processes, they have not provided sufficient data to allow a theoretical analysis of the flow mechanisms. In our laboratory, we are performing experiments which provide detailed information on the oil recovery, watercuts, flow rates and tracer concentrations produced from individual layers. The results of these experiments are being analysed using numerical simulation, in order to reproduce the flow mechanisms quantitatively. Earlier work performed at Winfrith used a heterogeneous core made from a sandstone cylinder with the centre removed and replaced with a pack of glass ballotini. This work has recently been extended using a rectilinear core assembly, and the results of these later studies are discussed in this paper.
Laboratory testing and evaluation of a new chromium(III) [Cr III] acrylamide-polymer gel technology for conformance-improvement-treatment (CIT) use are reported. This paper is primarily limited to discussing the gel technology as applicable to fracture conformance problems.
Several notable features of the gel technology are as follows. The gels, as injected in the field, are a single fluid system. Gels are made by simply adding a single aqueous crosslinking-agent solution to the aqueous polymer solution. The base chemical of the cross-linking agent is a readily available and relatively inexpensive CrIII chemical. An entire family of CIT gels, ranging from highly flowing to rigid rubbery gels, can be produced by varying the formulation of the same chemical set. Thus, the new gel technology is applicable to a wide range of conformance problems. Highly controllable gel times, ranging from minutes to weeks, are possible and can be preselected. Gels have been shown to be stable for extended periods of time when aged at temperatures ranging from 55 to 255F (13 to 124C]. Over the same temperature range, the gels have been shown to possess exceptional yield strengths (resistance to flow) and to be effective plugging agents. The gels are relatively inexpensive because they typically contain 98 to 99.7% water. with the remainder being low cost chemicals. Gels of the new technology are insensitive to oilfield interferences and environments, including H2S. They are compatible with all tested oilfield fluids and equipment and with all tested reservoir rocks and minerals. The gels can be made over a polymer solution pH range of at least 4.0 to 12.5. Gels can be formulated with low-molecular-weight polyacrylamide polymers when low viscosity (watery) treatment fluids are required. The gels can be chemically degraded (reversed).
Laboratory studies are described which show the dependence of gelation rate and gel strength on the following parameters: 1) polymer type, concentration, molecular weight, and hydrolysis level; 2) polymer-to-chromium ratio; 3) temperature; 4) polymer solution pH; and 5) salinity. Gels are shown to exhibit favorable phase-stability, shear, and leakoff properties. A new bottle-testing scheme is described. Bottle testing is used to effectively, rapidly, and inexpensively monitor in a semi-quantitative manner gelation rate and gel strength as a function of time over a broad range of temperatures and gel parameters. Gel viscosities, as determined by dynamic oscillatory measurements, are used to substantiate bottle-testing findings and trends. For selected rigid gels, gel breakdown pressures in porous media and yield pressures are reported.
New Gel Technology
The intent of this paper is to report on laboratory testing and evaluation of a newly developed, promising, and patented gel conformance-improvement-treatment (CIT) technology where aqueous gels are formed by crosslinking acrylamide polymers (polyacrylamide or partially hydrolyzed polyacrylamide) with a chromium(III) [CrIII] crosslinking agent. The cross-linking agent is a mixture of complex CrIII ions containing low-molecular-weight carboxylate anions, in association with other anions. The preferred carboxylate anion is acetate. The crosslinking agent, as added to the polymer solution, is predominantly an oligomeric chromium complex ion.
The crosslinking agent is highly water soluble and readily mixes with acrylamide-polymer solutions. The preferred CrIII crosslinking-agent base chemical is relatively inexpensive and readily available in the form of a concentrated aqueous solution. Typically, the cost of the crosslinking agent during our field tests has run about 15 to 20% of the polymer costs. In contrast to highly toxic CrVI2-5 , CrIII is relatively non-toxic and has been reported to be an "essential micronutrient" for humans. CrIII, in low concentrations, is relatively non-toxic to aquatic life.
This paper presents an update of "The Jobo Steamflood Project-Evaluation of Results". Although an adverse condition, such as the presence of a strong natural water drive in this reservoir, which prevents pressure depletion by primary steam stimulated production, 41.5% of the STOOIP has been produced, from an estimated final recovery of 45%.
Results from this mature project include a geological description of the oil bearing formations, basic petrophysical and fluids properties, a summary of oil production/steam injection statistics, well completions including thermal insulation of steam injection wells, surface facilities and associated processes with emphasis in recent technological developments, and analysis of front tracking schemes and their results.
Since preliminary results of this project were presented, substantial knowledge has been gained, which is being used in the planning of commercial development of Venezuela's huge Orinoco Belt.
The Jobo Steamflood Pilot Project (JSPP) represents an important step in the development of the appropriate technology for exploitation of the vast amounts of extra-heavy and non-conventional oil contained in the Orinoco Belt. The exploitation scheme of this 1.2 x 10-12 bls (1.9 x 10-11 m3) of oil in place will consist of successive steam stimulation cycles before beginning a steamdrive. The JSPP Project was carried out in the Jobo Field, in order to use existing infrastructure and because reservoir and fluids characteristics are essentially identical to those prevailing in the oil accumulations of the Orinoco Belt.
The JSPP was conceived with the purpose of obtaining information for future commercial development planning of this particular reservoir, and of the Orinoco Belt. The main objectives to be accomplished are:
- Evaluate technical and economic feasibility of steamdrive. The presence of a natural water drive in this reservoir prevents pressure depletion by primary steam stimulated production. Nevertheless, if the steamflood is successful under this original pressure condition, it would guarantee success in the Orinoco Belt under depleted pressure conditions.
- Determine recovery factor.
- Calibrate numerical simulators which will be of great help in comparing exploitation alternatives.
The JSPP is located in the Jobo Field, South of the State of Monagas in Eastern Venezuela, and just North of the Orinoco Belt, as seen in Fig. 1 .
The Jobo field reservoirs belong to the Oficina Formation, which is divided into the Pilon, Jobo, Yabo and Morichal Members, as seen in the stratigraphic section of Fig. 2. The project is in the "C" sand of the Morichal Member because of its best quality and thickness.
A recent study (SPE paper 16728) described a preliminary investigation of the effects of some commercial gelants on reduction in CO2 permeability. That paper presented a method for examining gelant systems by vial tests, core tests, and two-dimensional, flow visualization studies in high-pressure, glass micromodels. For the preliminary study, tests were conducted with CO2, San Andres crude oil, and brine at 1500 psi and 105F to simulate west Texas/southeast New Mexico conditions. The micromodel studies were coupled with the core tests to assess the pore-level mechanisms responsible for permeability reduction. Each of these commercial gelant systems demonstrated some deficiency in the desired performance in the brine/CO2 systems under investigation.
This paper presents follow-up lab-scale studies with newer gelant systems that are shown to be more stable under the same brine/CO2 conditions. Gelation kinetics are discussed, and results of core tests with a phenolic gel and a vinyl gel are described. These gels are more rigid than the gels first investigated, and the micromodel studies indicate that they are much more effective in remaining stationary in channels or high-permeability flow paths.
Carbon dioxide flooding is one of the fastest growing enhanced oil recovery methods. It can be economically attractive despite the poor mobility ratio between CO2 and the oil. However, many CO2 field projects have experienced early gas breakthrough caused by reservoir heterogeneities, such as fractures, channels, or high-permeability streaks. When most of the injected CO2 enters high-permeability zones, oil recovery efficiency and the economics of the process are reduced.
Several water-soluble chemical gelants have been proposed to restrict flow of fluids in high-permeability thief zones, especially in waterfloods. Many of the gelant systems proposed for this application include gel structures that are somewhat fluid. A recent study described a preliminary investigation of the effects of some commercial gelants on reduction in CO2 permeability. The commercial gelants that were evaluated included polyacrylamide and xanthan gum crosslinked with chromium(III) ion as well as acrylamide monomer that is polymerized and crosslinked in situ. Each of these gelants demonstrated some deficiency in the desired performance in the brine/CO2 systems under investigation. Results of the first study will serve as baseline experiments for the evaluation of improved gelants for CO2 flooding applications.
This paper presents a follow-up study with newer gelant systems that were expected to be more stable under the same brine/CO2 conditions as in the prior study. Gelation kinetics and results of core tests with a phenolic gel and a vinyl gel are described. Since these gels can be more rigid than the gels first investigated, the goal of this work was to assess their effectiveness in remaining stationary in channels or high permeability flow paths during brine/CO2 water-alternating-gas (WAG) cycles.
One of the polymers previously studied for this application, xanthan gum, was used in slightly modified tests in the current study. The xanthan gum polymer used was Pfizer FLOCON 4800P, which is a broth containing 4.7% active polymer. Solutions of the xanthan gum polymer were crosslinked with Pfizer X-LINK 1000, a proprietary solution of chromium(III) ion. This gelant system will be designated XG/Cr.
In some micellar/polymer flooding pilots, severe problems associated with polymer stability and/or polymer injectivity have been experienced. These problems have contributed to less than optimal pilot performances. As a result, process strategies which do not employ polymer have been actively considered.
The strategy evaluated in this paper consists of a low concentration (less than 2 wt% active) micellar fluid which is injected as a large bank (greater than 20% Pv) and which forms a lower phase microemulsion under prevailing reservoir conditions. This micellar bank is in turn displaced by a water drive with no provisions for nobility control. Such a process was deemed to be simplified in application and to be potentially of low economic risk in that a large bank, lower phase displacement was assumed to be less susceptible to the deleterious effects of reservoir heterogeneity in the absence of nobility control agents.
Performance predictions were based first upon the successful simulation of laboratory field core tests for which fluid physical properties, phase behavior, chemical retention, and oil recovery were well-quantified for a commercially available surfactant system. Simulation matches were obtained with a nonproprietary chemical flooding simulator. Once suitably calibrated, the simulator was then applied in a predictive mode to a field scale displacement in a typical 21-acre, four-layered five spot in the target reservoir.
The sensitivity of the process to slug size, chemical concentration, capillary desaturation characteristics, injection rate, microemulsion viscosity, and other design strategies was determined.
The results suggest that the current laboratory system is unacceptable for field testing because the system fails to produce sufficiently low interfacial tensions to significantly desaturate waterflood residual oil in the lower phase environment. The study does, however, point out useful goals, guidelines, and evaluation strategies by which the economic potential of future process designs can be assessed.
In this paper, we will evaluate the concept of low concentration surfactant flooding in the absence of nobility control agents. As such, this work represents a significant departure from accepted micellar flooding practices in that oil displacement efficiency, effective micellar slug propagation and favorable reservoir sweep may be to some degree sacrificed by omitting nobility control agents. This approach, however, is a direct recognition of the fact that not only oil recovery efficiencies but also process costs and timely oil recovery rates will together ultimately dictate the economic viability of micellar flooding.
Specifically, this approach to micellar flooding was explored as a consequence of the severe operational difficulties we and others have encountered with the preparation and injection of polymer solutions. In pilot operations, these problems have manifested themselves as excessive adsorption and trapping, injection face plugging, poor polymer stability or coacervation with surfactant. Each of these problems has at times led to the substantial loss of injection capacity and thereby to severely diminished oil rate expectations. In other instances the loss of polymer integrity through chemical biological, mechanical and thermal degradation has resulted in the insufficient mobility reduction of the micellar drive bank.
This paper describes a technique for inferring formation wettability from measurement on crude oil/brine pairs. This dynamic Wilhelmy plate technique yields a quantitative measure of wettability in a form which is directly comparable to other forces in the reservoir. Exposure to air affects the measured wettability of crude oil, and a device is described for avoiding contamination.
Formation wetting preference affects the success of most conventional and enhanced recovery methods. Waterflood performance depends on the amount of imbibition which can be expected of a reservoir and oil recovery from EOR Methods is affected by the formation wettability. Matching and predicting performance successfully depends on the ability to determine the degree of wetting preference of the formation. The relative permeability, capillary pressure, electrical response, and occasionally the rock mechanical response all depend on the position of the fluids in the pores. These details have been covered in a series of exhaustive review papers by Anderson.
Every technique for estimating formation wettability has drawbacks. The easy tests are qualitative and the quantitative tests are expensive and time-consuming. The dynamic Wilhelmy plate technique described here provides an inexpensive and easy-to-understand quantitative wettability test. The result of the test is a physically meaningful value which can be directly compared to other forces in the reservoir.
Wetting character is divided into three regimes usually based on advancing contact angle: water-wetting for angles less than 75 oil-wetting for angles greater than 105, and intermediate-wetting for contact angles between 75 and 105. Because the dynamic Wilhelmy wettability test determines both advancing and receding contact angles, it distinguishes another characteristic wetting in crude oil/brine systems, termed "hybrid" wetting, in which the water-advancing contact angle is greater than 90 and the water-receding contact angle is less than 90. In a hybrid system, whichever liquid is in contact with the surface tends to remain in contact with the surface until it is displaced because of other overriding forces. In this paper, systems with both advancing and receding adhesion tensions greater than zero are termed water-wetting; both adhesion tensions less than zero are termed oil-wetting; and those for which the adhesion tensions switch sign as described above are termed hybrid-wetting.
This paper discusses the use of the dynamic Wilhelmy plate technique for evaluation of the wettability of several crude oil/brine systems. A method for performing the tests in the absence of air is described.
Discussion of the Method
Wilhelmy described the basic technique for measuring surface and interfacial tensions (IFT) in 1863. It has been used by surface chemists for many years, primarily to study vapor/liquid/solid interfaces. A computer-controlled device has been developed for studying both vapor/liquid/solid and liquid/liquid/solid interfaces. A thin plate is suspended from a computer-monitored microbalance over a vessel containing oil and brine. A computer-controlled stepper motor moves the vessel upward causing the plate to pass through the air/oil interface and the oil/brine interface. Multiple wetting cycles can be performed under computer control without disturbing the system.