Viscous Crude Oil Research Articles

Successful Conversion of the Pikes Peak Viscous-Oil Cyclic Steam Project to Steamdrive

Summary This paper describes conversion from steam stimulation to steamdrive in ahigh-viscosity oil reservoir. Field testing of operating strategies helped todevelop conversion and operating criteria. The successful steamdriveperformance was attributed to reservoir preheating and injector/producerinterwell communication that were established during cyclic operations. Steamdrag and gravity drainage are the main recovery mechanisms. Introduction The Waseca formation in the Lloydminster heavy-oil deposits of Alberta and Saskatchewan contains a viscous crude oil that was produced unsuccessfullyunder primary produced unsuccessfully under primary recovery. Steam stimulationwas initiated in 1981. Good response led to expansion of the pilot to itspresent 106 thermal wells, drilled pilot to its present 106 thermal wells, drilled in a general 3-ha inverted seven-spot configuration (Fig. 1). Pikes Peak wells exhibit very good cyclic performance until 20% to 30% of theperformance until 20% to 30% of the original oil in place (OOIP) has beenrecovered. On the basis of excellent reservoir properties and frequentobservation of properties and frequent observation of apparent heat and masstransfer between wells, evaluation of follow-up drive processes was initiatedin 1983. The major technical hurdle was the viability of a steamdrive processwith a high-viscosity (25 000-mPas) process with a high-viscosity (25 000-mPas)virgin oil. In 1984 a steamdrive test was initiated in a pattern where thefuture injector had communicated to five of six producers (Fig. 2). Thispattern has been used to identify the dominant production mechanisms and todevelop improved operating strategies. Following the early success of the firststeamdrive pattern, conversion criteria and operating strategies were refinedand additional patterns converted to drive. Despite the high initial oilviscosity, steamdrive has proved to be a technical and economic success, provedto be a technical and economic success, with pattern steam/oil ratios (SOR's)of 2.9 to 8.3. Geology and Reservoir Description The Lloydminster heavy-oil deposits (Fig. 3) form the southern end of thediscontinuous trend of Lower Cretaceous Mannville Group bitumen and heavy-oildeposits that also are present in the Athabasca and Cold Lake areas. Most Lloydminster deposits are able to produce 3 % to 8 % of the OOIP under primaryconditions, although sustained p production could not be achieved p productioncould not be achieved at Pikes Peak in 1981 because of sanding problems. Thereservoir contains viscous problems. The reservoir contains viscous crude oilwith a gravity of 0.99 g/cm3 and a gas-free viscosity of 25 000 mPas atreservoir temperature (18 degrees C). Most development in the Lloydminster areahas been in the Sparky formation, but other Mannville formations, including thesheet-like regional Waseca formation sandstone reservoirs in the easternportion, have also been exploited. Occasionally, as at Pikes Peak, areallyrestricted, clean, thick Pikes Peak, areally restricted, clean, thick channelfacies occur. Van Hulten concluded that deposition of the Pikes Peak channelfacies was contemporaneous with that of the regional Waseca sands, andchannel-sand thickness variations were the result of migrating point bars. Alocal structural high allows the project area to be free of bottomwater (Fig.1). The Waseca formation at Pikes Peak has been divided into a well-sorted, unconsolidated, predominantly quartz, highly permeable (5 to 10 darcies), homogeneous lower permeable (5 to 10 darcies), homogeneous lower unit and asand/shale interbedded upper unit (Table 1). Fig. 4 is a type log for the Waseca interval. The quality of the upper unit decreases upward as a result ofdecreasing grain size and increasing clay content, but the higher-quality"A" interbeds often are in communication with the homogeneous sand unitand contribute to pilot oil production. production. Initial Pattern Conversion(1A11–1) Selection Criteria and Conversion. Planning for conversion of mature areasto Planning for conversion of mature areas to steamdrive began in 1983. It wasfelt that, at the end of economic cyclic operations, a large undrained area ofhigh residual oil saturation would remain. The results of van Lookeren and Taber and Martins indicated that steam override would likely occur at pikespeak and that preheating would be required to reduce oil viscosity and tolessen the effects of steam channeling. Five developed patterns were examinedon the basis of well maturity (number of complete steam cycles, recovery) andoccurrence of interwell communication from the proposed injector to patternproducers. proposed injector to pattern producers. JPT P. 1510

In-Situ Saturation Measurements Improve Analysis and Interpretation of Laboratory Miscible and Immiscible Displacement Processes

Summary A laboratory evaluation of miscible and immiscible oil recovery processes was performed on a sandstone core composite containing viscous crude oil. Because conventional effluent data cannot clearly identify the evolution of transient saturation distributions, in-situ saturation monitoring was used to provide distributed saturation histories. The data obtained suggest that phase behavior is a major factor determining the amount and distribution of residual oil.

Stability of core-annular flow with a small viscosity ratio

It is known that the stability problem for core-annular flow of very viscous crude oil and water is singular, the water annulus appears to be inviscid with boundary layers at the pipe wall and at the interface. In the present paper, this singular problem is treated by the method of matched asymptotic expansions using ε=m/Rα as a small parameter. There are two cases of instability corresponding to different positions of the critical point in the annulus. One case is when the critical point is far away from the interface, the other is when the critical point is close to the interface within a distance of order ε1/3. In both cases, we derive the equations for the eigenvalues, and give the explicit forms for the neutral curves. The stability problem is also treated by the modified finite element code used by Hu and Joseph [J. Fluid Mech. 205, 359 (1989); Phys. Fluids A 1, 1659 (1989)], taking into account the boundary layers at the pipe wall and at the interface. The results of the two methods agree where they overlap, but the finite element technique goes further.

CONCENTRATED VISCOUS CRUDE OIL-IN-WATER EMULSIONS FOR PIPELINE TRANSPORT

The need to utilize viscous crude oils will increase in the next decade. One means to facilitate pumping of heavy crudes in pipelines is to transport them as concentrated oil-in-water emulsions. Stable emulsions could be prepared by alkali treatment with four of seven viscous crudes studied. Surfactants are formed by reaction of natural acids in the crude with alkali. At crude volume fractions of 60%, emulsion apparent viscosity was lowered as much as 10,000 times. Viscosities of crude emulsions formed by alkali treatment varied with the nature of the crude and with the ratio of base added to the TAN of the crude. Emulsion viscosities and particle diameters reach extrema close to the equivalence point. The addition of tall oil enhanced the emulsification ability of some of the crudes with alkali treatment, but one crude required non-ionic surfactant to form an emulsion.

THE RECOVERY OF SPILLED HEAVY OIL WITH FISH NETTING

ABSTRACT Most oil spill containment and recovery equipment is not suitable for use with heavy viscous crude oils. For these oils, nets have been suggested as a containment device, and some laboratory and open sea studies of their suitability have been conducted. We have used a trolley system in a large outdoor pool to measure net loading and to observe the behavior of nets in containing heavy neutrally buoyant oil (viscosity of 3 × 105 cSt at 10° C). For moderate towing speeds of about 0.3 meters per second, inexpensive ¼ inch mesh fish netting was found to be a suitable containment device.

M/V ALVENUS: ANATOMY OF A MAJOR OIL SPILL1

ABSTRACT At 12:36 p.m. on July 30, 1984, the United Kingdom tank vessel Alvenus grounded with catastrophic structural failure in the Calcasieu River Bar Channel about 11 nautical miles south-southeast of Cameron, Louisiana, creating the largest oil spill from a ship ever encountered in the Gulf of Mexico. The vessel's hull buckled and fractured vertically on both the port and starboard sides and across the tank tops in way of its No. 2 port, center, and starboard cargo tanks. Between July 30 and August 4, 1984, the Alvenus discharged approximately 2.7 million gal of viscous Venezuelan Merey and Pilon crude oil into international waters of the Gulf of Mexico. Attempts to contain and recover the oil at sea were rendered ineffective by rough seas and the magnitude of the spill. A well-defined 75-mile slick of oil traveled west from the Alvenus for over 100 miles, arriving on Texas beaches on August 3 and 4 between the town of Gilchrist, and San Luis Pass at the west end of Galveston Island. Beach cleanup crews were reasonably prepared for the massive influx of oil and were able to remove the oil with only minimal environmental damage. Sensitive inland estuaries were spared by a combination of chance (the oil passed inlets during ebb tides) and prestaged booms. However, economic damage was great, since Galveston's resort beaches were heavily oiled during the height of the tourist season. Damage to the vessel was extensive and estimated at $4.9 million by the vessel's owner. Loss of cargo was estimated at approximately $1.7 million at $26.00 a barrel. The Coast Guard and cleanup crews encountered a major problem when a large portion of the slick approached the shoreline, absorbed suspended solid particles, and sank in the nearshore surf zones at Galveston Island. No effective method of collecting the oil in the submerged state was discovered. Cleanup crews had to wait until the oil beached itself, a process that took several weeks

Enhanced Oil Recovery of Acidic Crudes by Caustic Cosurfactant-Polymer Flooding

A laboratory study of alkaline flooding behavior of three viscous acidic crude oils has been carried out. Optimum flooding formulations have been selected by constructing 'activity maps' of the phase behavior of the crude oil-NaOH mixtures as a function of oil fraction and NaOH concentration. Crude oil-NaOH mixtures demonstrate Optimum phase behavior within a very narrow range of NaOH concentration. Addition of nonionic surfactant Triton X-100, as cosurfactant, has been found to enlarge the optimum region of the activity map very considerably. The results obtained from a series of one-dimensional core flow experiments using Berea sandstone cores indicate that simple application of dilute NaOH solution does not recover any significant amount of additional oil as compared to waterflooding. Optimum caustic-cosurfactant solutions with adequate mobility control, using polyacrylamide Cyanatrol 960, recovered upto 96% of oil in place. Caustic consumption appeared to be a significant factor and unfavorable mobility ratio precludes high oil recovery even when caustic solution initiates oil mobilization.

磁性二重管路の特性とその応用

A new electric pipe heating system and a new circuit element composed of two magnetic pipes with coaxial structure are proposed.Application of AC current to the magnetic coaxial pipe structure causes the latter to act as a useful pipe heater to transport highly viscous crude oil and to be useful element in detecting the amplitude or phase of the current. This is possible because the voltage of the outside surface of the magnetic coaxial pipe is extremely small due to its remarkable skin and proximity effect. In this paper we present an analysis of the magnetic coaxial pipe and the experimental results of some applications. Using the magnetic pipe as a heater by applying AC current the coaxial pipe structure, the heat generation occurs uniformly and the earth current is very small. This system is particularly useful in a long distance pipeline because of its small impedance. The small coaxial pipe element fabricated with soft magnetic material can detect broadband frequency current accurately without any contact because the impedance of the outer pipe varies with the unbalanced reciprocal current.

The Effect Of Temperature On The Interfacial Tension Of Heavy Crude Oils Using The Pendent Drop Apparatus

Abstract A series of interfacial tension (IFT) measurements versus temperature were carried our at a constant pressure using the Pendent Drop apparatus. The study was conducted with seven different samples of viscous crude oil using as the aqueous phases a source water for water injection, distilled water, and heavy water. The temperatures investigated ranged from ambient 10 160 °C. For two heavy oils if was found that the IFT initially decreased then increased with temperature and for one oil there was only an increase. For all other systems IFT either remained constant or decreased with increasing temperature. To investigate this apparent anomaly of increasing IFT with increasing temperature, a series of experiments were conducted to examine the effect of oxidation of the bitumen and also the effect of intermediate or light-end hydrocarbons which may hare been lost from the heavy crude oil system during the driving process. No just explanation for the increasing IFT was established. In a system where the density difference between the oil and the aqueous phase was from 0.01 to 0.002 gcm3, the Pendent Drop maintains its integrity. However it was found that the drop does not have the necessary shape to permit the determination of an accurate tension. Consequently for the heavier crude oils, modified procedures for measuring IFT were examined and are described. To overcome this problem the density difference between the two phases was increased by using heavy water as the aqueous phase. Introduction The interfacial tension between heavy crude oil and injection water under reservoir conditions plays a significant mechanistic role in the process of enhanced oil recovery. This interaction between the oil and water phases in steam flood recovery schemes is a function of temperature, pressure, and composition of both the hydrocarbon and aqueous phases. With highly viscous crude oils, increasing the temperature of the formation is the most significant factor in mobilizing the oil. However, to improve the efficiency of this process, the use of additives such as solvents, high pH control chemicals, or surfactants co-injected with steam, has been shown to enhance the oil recovery. The dominant mechanism in these cases, is a reduction in IFT at the oil/water interface resulting in the mobilization of oil by in-situ emulsification. Both an increase in temperature and the use of certain additives are expected to cause a decrease in the IFT. The purpose of this study was to investigate this expectation for some heavy oils and waters. This study involved the examination of the effect of temperature on the IFT of a number of heavy crude oil and water systems using the Pendent Drop technique. This quantification of the IFT/temperature relationship is important in a number of areas including:the assessment of the application of chemicals in low- and high-temperature enhanced recovery processes.the study of the effect of IFT as it relates to emulsification of oil-in-water or water-in-oil.the establishment of high-temperature IFT relationships associated with thermal recovery mechanisms.

Discrimination of Crude Oil and Water in Sand and in Bore Cores With NMR Imaging

Summary Nuclear magnetic resonance (NMR) imaging techniques were used to study the mobile proton content in prepared samples containing mixtures of crude oil, water, and sand. The measured proportions of viscous crude oil agree well with the actual values. Discrimination of light crude oil and water was demonstrated by proton chemical shift differences. A bore core sample also was examined and gave clear images from its oil content.

Limitations on the Oil/Steam Ratio for Truly Viscous Crudes

Summary Scaled physical model studies have yielded results that suggest very viscous crude oils with a viscosity somewhat greater than that of San Joaquin Valley crudes cannot be economically recovered by an unassisted steamdrive. Introduction Steamdrive has been used successfully for almost two decades for the economic recovery of viscous crudes. One of the large targets for steamdrive has been implicitly assumed to be the large accumulations of very viscous crudes with a gravity less than 10API [1 g/cm 3]. Some of the early scaled physical model studies of the steamdrive indicated that the viscosity of the oil at steam temperature had a significant effect on the efficiency of the steamdrive. The experimental work indicated that the growth of a steam zone was not independent of the viscosity of the reservoir fluid, contrary to the implicit assumption made in the Marx-Langenheim analysis of the steamdrive. This raised questions about whether the steamdrive could be successful in recovering very viscous crudes and bitumens. Some investigators point out that other factors, such as pattern size, optimal injection rates, etc., limit the application of the steamdrive. However, most of these factors are controllable and can be adjusted before the steamdrive is started. Further, some investigators have concluded from laboratory and field results that the hot-water drive associated with steam injection made a significant contribution to recovering viscous crudes. There can be little question that the viscosity of the crude is a factor in water-drive efficiency. Even assuming that the viscosity of the crude will not affect its ultimate residual saturation to a water drive, the efficiency of a water drive in terms of the number of PV's required to reach the residual must be significantly affected by the oil viscosity. Therefore, the hot-water-drive components of steamdrive cannot be expected to contribute significantly in attempts to recover very viscous crude oils. A series of scaled physical model studies was undertaken to elaborate on the effect of viscosity on steamdrive. Preliminary results have been reported earlier; but in view of the important issues raised by the findings of this work, the completed study is reported here. Experimental Procedure The use of scaled physical models and the procedures used for modeling steamdrive have been described already. To achieve the goal of this work, the models were saturated with prototype crudes that had a range of viscosities at 100F [38C] from 3 cp to more than 100,000 cp [0.003 to 100 Pa s]. The initial oil saturation was 85 to 92 % in a uniform, confined 6-acre [145 687-M2], five-spot pattern. The model simulated one quarter of a confined 6-acre [ 145 687-m 2], five-spot pattern with a uniform porosity of 35%. In most of the pattern with a uniform porosity of 35%. In most of the experiments the prototype reservoir thickness was 73.5 ft [22 m] and the absolute permeability in the range of 1 to 2 darcies. A few experiments also were conducted with a model that corresponded to a reservoir only 27 ft [8 m] thick. In all experiments the steam initially coursed through the model at the top of the reservoir-i.e., it overrode the oil column either fortuitously or by initially establishing a gas saturation amounting to 1 to 3% of the reservoir volume. In actual oilfield operations, the steam may or may not enter initially at the top of the reservoir, depending on the reservoir lithology and the distribution of the saturating fluids. However, in a steamdrive the steam eventually does reach an upper barrier to its further flow, and the overall performance of the steamdrive will approach the performance of a reservoir in which the steam did enter initially at the top. Because initial entry in these experiments was always at the top, a measure of consistency in the various experiments was introduced. To make a valid comparison between all the runs, the rate of steam injection was standardized at a value that had been determined earlier as optimal for prototype crude oils with a viscosity at 100F [38C] in the range of 1,000 to 5,000 cp [ 1 to 5 Pa s] (San Joaquin Valley crudes)-130 to 150 B/D [21 to 24 m3/d] of water (converted to steam) per acre. The viscosity of the crudes at the prototype steam temperatures varied from 0. 15 to 85 cp [0.00015 to 0.085 Pa s]. Finally, various runs of steamdrives were compared by use of the "stable" oil/steam ratio that developed following steam breakthrough (see Fig. 1). JPT P. 1123

The Coaxial Pipe Electric Heating System for Pipelines

To transport highly viscous crude oil efficiently through pipelines, some electric heating systems have been conventionally used. But they include heating cables or tubes, which are troublesome in submarine pipeline construction. A new electric heating system without a cable has been developed and is applicable to long-distance submarine pipelines. This system has a coaxial steel pipe structure, using the pipes as a heater by applying AC current to this coaxial circuit. In this paper, electromagnetic analysis on this system, experimental study using a 30-m length test pipeline, and mechanical tests on the electric insulating structure of the system are described.

The Replacement of Hydrocarbon Diluent With Surfactant and Water for the Production of Heavy, Viscous Crude Oil

Summary Viscous crudes often are produced by means of a low-viscosity hydrocarbon diluent to decrease viscosity of the produced fluid in the tubing and the flowlines. Rod-pump difficulties may result from the slow fall of the rod string caused by high fluid viscosity. The use of a diluent reduces these rod-fall and associated flow problems. Our goal was to replace the diluent completely with a water/surfactant system without increasing the flowline pressures. This was accomplished with a produced water/surfactant mixture, However, in one field we found that using a combination of diluent, surfactant, and water was the most economical way to produce the crude. The crude is dispersed in a water-external system so that the viscosity is decreased appreciably. We initially evaluated different chemicals in the laboratory. Later tests were on individual wells, a 6-well pilot, and finally a I5-well pilot. Economics of the new system are projected to be more favorable than those of using diluent alone. This system can be used not only for heavy crudes but also for waxy crudes that have high pour points and are thus difficult to produce. It allows a lower pumping cost because of reduced viscous drag and can be more economical than some diluent systems. Introduction Our previous work1 described various techniques for reducing the viscosity of waxy crudes that are also applicable to heavy crudes. In addition to the preparation of oil and water emulsions, these techniques included:dilution with lighter oil,preheating with subsequent heating in the line,preheating and insulating, andinjection of water to form a water ring. McAuliffe describes oil-in-water emulsions.2,3 We also have received patents in this area.4–8 The production of heavy, viscous crude at Cat Canyon field near Santa Maria, CA, requires the use of a viscosity reducer that allows the crude to be pumped from the wellbore to storage. Kerosene distillate (KD) has been used for this purpose at Cat Canyon for some time. However, cost and availability of KD at Cat Canyon caused some concern, so we began a research program to find an alternate to the KD mode of production. Our goal was to reduce viscosity of the heavy crude by some way other than dilution with a hydrocarbon solvent. By producing an oil-in-water emulsion, we succeeded in reducing the viscosity of the heavy crude oil from ~3,000 cp at 170 to 200°F to only 50 to 100 cp at these temperatures. We produced the oil-in-water emulsions by mixing the oil with water that contained an emulsifier. Another part of our objective was to produce a reversible oil-in-water emulsion that, after being prepared at the well, would have just enough stability to reach the heater-treater before separating into an oil layer and a water layer. In other words, we wanted to produce an emulsion that was not too stable; otherwise, it could cause problems at the heater-treater. The initial laboratory phase consisted of screening 44 commercial oilfield emulsifier-type chemicals to find a product that would form a low-viscosity. oil-in-water emulsion when used with the viscous Cat Canyon crude. Commercial Surfactant A. which gave the best results in the laboratory, also gave the best results in field tests conducted at Cat Canyon. The commercial product was more economical than KD alone, but we wanted the least expensive product. Therefore, it appeared more economically attractive for us to develop our own emulsifier packages. The work covered in the first part of this paper was conducted in wells at Cat Canyon field, first with commercial oilfield emulsifying-type chemicals and second with emulsifier packages developed in our laboratory.

Overview of Artificial Lift Systems

Summary This paper gives guidelines to assist in the selection of artificial lift methods. The most important guideline is determination of the flow rates possible by each method. This requires preparation of pressure/flow rate diagrams combining well-inflow performance relationships with tubing intake curves. The tubing intake curve includes, pressure loss in the complete piping system and/or pressure loss in the complete piping system and/or pressure gains by the pumping method. Many other pressure gains by the pumping method. Many other factors other than rate, such as location, retrievability by wireline, corrosion, paraffin, scale deposition, cost, operating life, and others, influence the final selection of lift equipment. Introduction This paper provides an overview of artificial lift systems and gives guidelines indicating when one system is better to use than another. Advantages and disadvantages are given with examples in the selection of lift methods. This list represents the relative standing of lift systems based on the number of installations throughout the world:sucker rod pumping (beam pumping)gas liftelectric submersible pumping,hydraulic piston pumping,hydraulic jet pumping,plunger piston pumping,hydraulic jet pumping,plunger (free-piston) lift, andother methods. This differs according to field, state, and country. New lift systems are being developed and tested continually. The lifting of heavy viscous crude oils requires special attention, and methods designed specifically for this purpose are being tested. Wells located offshore and in deep water present specific problems, and surface- space limitations become important. The artificial lift method should be considered before the well is drilled. Obviously this cannot be done on wildcat wells. but it must be done on all subsequent development wells. The drilling program must be set out to ensure hole sizes that permit adequate casing and tubing sizes. permit adequate casing and tubing sizes. One serious limitation to artificial lift installations has been the installation of small casing sizes, which limits the installation to specific tubing sizes to obtain the objective flow rate and, in particular, limits the size of retrievable gas lift equipment and/or pumping equipment. The installation of gas-lift mandrels that accept only 1 -in. (2.5-cm) OD gas-lift valves is common in the U.S.. and serious limitations on gas passage volumes are imposed on the system with this small valve. Also, the better performance characteristics of the 1 1/2-in. (3.8 1 -cm) OD valve are lost. For the pumping systems. the smaller capacity pumps must be used in the smaller casing sizes, and sometimes the advantage of retrievable pumps is lost. pumps is lost. Surface-space limitations become an important factor. For example, if large compressors for gas lift or large generators for electrical pumping are anticipated for offshore platforms, provisions must be made in the original design to allow for both weight and space on the platforms. Some engineers are invariably optimistic about platforms. Some engineers are invariably optimistic about natural flow in the planning stage, and in many instances they still maintain that artificial lift will not be required during the life of a field. This leads to very poor planning, especially on offshore facilities. planning, especially on offshore facilities. In the design of artificial lift systems for a well, it is recommended that it initially be treated as if it were a flowing well--i.e., a production systems graph should be prepared to see if the well is capable of flowing and, if it is, at what rate. The artificial lift analysis can be placed on the same plot. Numerous flowing wells will show increased flow rates when placed on artificial lift. The purpose of any artificial lift system is to create a predetermined tubing intake pressure such that the predetermined tubing intake pressure such that the reservoir may respond and produce the objective flow rate. The design and analysis of any lifting system can be divided into two main components. The first is the reservoir component (inflow performance relationship), which represents the well's ability to produce fluids. JPT P. 2384

Specialized Pumping Techniques Applied to a Very Low-Gravity, Sand-Laden Crude - Cat Canyon Field, California

Summary With the application of specially designed pumping and treating equipment, we are producing crude oil as low as 4°API (1.044 g/cm3) containing up to 70 vol% of sand. An important part of this system is the bottom hole pumping equipment that has allowed primary production rates in excess of 150 B/D (24 m3/d) oil from wells that were restricted to less than 10 B/D (1.5 m3/d) oil when produced with conventional rod pumps and sand control completion methods. These pumps are available commercially. Techniques developed may be extended to other areas where production is limited by problems inherent with highly viscous crude oils and excessive sand entry. Introduction Problems with pumping extremely viscous crude oils are well known to all operators who produce low-gravity crude oil. Rod floating, overloaded pumping units, and pumps plugged with heavy crude oil are common occurrences. Likewise, such problems as stuck pumps, eroded tubing and sucker rod couplings, and stripping jobs are common wherever sandy production occurs. We experienced all these problems in producing the Brooks reservoir, located in the Cat Canyon field, Santa Barbara County, CA, where oil gravity averages 6°API (1.029 g/cm3), and the production contains up to 70% sand. Over a 5-year period these problems were ameliorated with the development and successful application of special downhole pumping equipment. This paper up-dates a previous work on this topic.1 The Brooks reservoir sand is an unconsolidated basal member of the Pliocene Sisquoc formation. The sand is very fine-grained and well-sorted, with a medium sand-grain size of 0.0065 in (0.165 mm) and a Trask sorting coefficient of 1.2. Reservoir depth ranges from 2,500 to 3,500 ft (760 to 1070 m); average net sand thickness is 150 ft (46 m). A type log is shown in Fig. 1. There is no significant primary water production, and the zone produces at less than 1 to 2 % water cut, except where wateror steam injection has occurred. The oil gravity of Brooks zone is among the lowest produced in the world, and ranges from 11 °API (0.993 g/cm3) in the upstructure area to about 0°API (1.076 g/cm3) downstructure at the reservoir limits. Reservoir oil currently averages about 6°API (1.029 g/cm3) and has 15,000-cp (15-Pa·s) viscosity at reservoir conditions. Reservoir properties of the Brooks sand and fluids are summarized in Table 1. Operating Experience With Conventional Equipment Production from the Brooks zone began in 1909 in the area where highest oil gravity occurs. These early wells were completed with 250-mesh [0.25-in. (6.35-mm)] slots or 1/2-in. (12.7-mm) holes through the zone, which allowed almost unrestrained sand production from the unconsolidated formation. Initially, these wells flowed up to400 B/D (64 m3/d) of 10°API (1.0 g/cm3) oil containing about 15 % sand. Cumulative recovery from this old part of the field is now more than 10% of the OOIP. Individual wells have produced over 400,000 bbl (64 000 m3) of oil and 40,000 bbl (6400 m3) of sand over a 40-year life. To pump the highly viscous oil with conventional pumping equipment it was necessary to inject a distillate into the wellbore, which blended the native oil up to about 12°API (0.968 g/cm3).

The HEP Pumping Unit: Performance Characteristics, Potential Applications And Field Trial Results

Abstract The HEP pumping unit, which is the result of a four-year development program by Canadian Foremost Ltd., constitutes an alternative to the familiar beam pumping, unit as a means of transferring energy from the prime mover to the sucker rod string of a pumping well. This paper will address some basic concepts which are part of the HEP system design and will describe some of the resultant unit performance characteristics, The potential for enhancement of pumping well operations utilizing the high degree of control over rod string motion attainable with the HEP system is discussed, together with the results of a number of field trials in the Lloydminster area and some plans for further unit evaluation and development. A cost and capacity comparison with conventional beam pumping units is also included. Introduction Work which led to the development of the HEP pumping unit commenced in late 1975, Canadian Foremost became involved in early 1976 and to? date funding of the HEP' development program has amounted to approximately two and one half million dollars. The HEP unit does not represent a single specific technological breakthrough. It is best described as an engineered system which links together a number of components representing the state of the art in several areas of technology. The use of Hydraulics to transmit energy to the sucker rod string, Electronics to control the polished rod motion and Pneumatics for counterbalance effect is the source of the acronym HEP, Early field testing of the unit was carried out in late. 1976 and early 1977. Certain operational problems were identified and, after some design improvements, a more extensive field testing program was commenced during the fall of 1978, Although a portion of this field evaluation program still remains to be completed, encouraging results have been experienced in application of the unit to the lifting of highly viscous crude oil. Substantial production rate 4tcreases have been attained on wells with rod fall problems. At the time of writing, fifteen units were under lease or had been sold to various operators in Alberta and Saskatchewan. Basic Concepts The primary objective of the work which led to the development of the HEP unit was to eliminate the gearbox on a conventional beam pumping unit in favour of a high-torque / low-speed motor. Various types of hydraulic motors were known to exhibit this type of characteristic. Efforts to optimize system efficiency and control capabilities led to a unit geometry considerably different from that of conventional units (Fig. 1). The concept of using unit geometry to cause conversion of rotary motion in reciprocating motion was abandoned. The originally conceived high-torque/low-speed motor was replaced by a double-acting piston and cylinder motor, mounted above the wellhead, with the piston rod connected to the polished rod by means of a carrier bar and rod clamp. In this manner, it is possible to convert hydraulic power directly into reciprocating rod string motion (Fig. 2).

The Development of the Ardeshir Field

This paper describes the successful development of the Ardeshir Field offshore Iran, using an unconventional approach. Development centered on the use of two slant-mast, self-contained drilling rigs designed especially for this field. Sixty-six wells were completed using these slant rigs. Introduction Iran Pan American Oil Co. (IPAC) is a joint venture company formed by National Iranian Oil Co. and Amoco International Oil Co. on an equal partnership basis. IPAC operates four producing oil fields offshore Iran (Fig. 1).The Ardeshir Field (one of the four Amoco-operated fields) is located in 120 ft (36.6 m) water offshore Iran about 45 miles (72.42 km) west of Kharg Island. The field was declared commercial. In Dec, 1970, after drilling six mudline suspension, delineation wells. This paper describes the successful development of this large paper describes the successful development of this large unique reservoir, which required an unconventional approach. The structure is about 15 miles (24 km) long × 5 miles (8 km) wide, with a maximum oil column thickness of 150 ft (45.7 m). A moderately viscous sour crude oil [14 cp (3.4 mPa)] of 27 degrees API (0.9 g/cm) gravity is produced from the Ghar formation, an unconsolidated sand of Lower Miocene age.Core permeability of the Ghar sand averages 2.5 darcies, with porosities of about 30%. The oil zone is overlain by an initial gas cap with a 60-ft (18.3-m) gas column at the crest and underlain by an aquifer expected to be active and large in areal extent.Full-scale field development began in early 1976 with production starting in Nov. 1976. In Dec. 1978 the field production starting in Nov. 1976. In Dec. 1978 the field achieved our production objective rate of 200,000 BOPD (31 797 M /d oil) on a sustained basis from 61 active producers. Subsequently, one of the two slant-mast rigs producers. Subsequently, one of the two slant-mast rigs was released, and the remaining rig used for continued development drilling and workovers.Because of the relatively shallow depth of the producing formation, unusual techniques were employed producing formation, unusual techniques were employed to develop the field, The development program centered on the use of two slant-mast, self-contained drilling rigs that were designed specifically to operate from 28-slot, fixed platforms. Each platform had 10 vertical, eight 20 degrees, two 25 degrees. and eight 30 degrees conductors. The slant conductor concept was used to maximize the departure of the directionally drilled wells and thereby increase the drainage area of each platform. Sixty-six wells were completed using these slant rigs on the four 28-slot platforms installed. An additional nonloadbearing platforms installed. An additional nonloadbearing platform with nine vertical slots also was installed that will platform with nine vertical slots also was installed that will use a conventional jackup rig for drilling. Eventually, up to 10 platforms may be installed in the Ardeshir Field. Geology The Ardeshir Field produces hydrocarbons from an Oligo-Miocene age reservoir called the Ghar sandstone formation, which occurs 2,800 ft (853 m) subsea. This unit can be divided into three members:a basal carbonate called the Asmari,a middle member called the Ghar sandstone, andan upper carbonate-anhydrite unit called the Lower Fars pay. JPT P. 821

Geology of Gu-Dao Oil Field and Adjacent Areas: ABSTRACT

Gu-Dao oil field is located geologically in the center of Zhan-Hua basin, Bohai Bay hydrocarbon-bearing province, and geographically in the coastal zone of the lower Yellow River valley. Zhan-Hua basin is a Cenozoic block-faulted basin, with an area of 2,100 sq km. The intensive subsidence of the faulted blocks was followed by deposition of thick Tertiary continental strata (the Eocene series itself is as thick as 4,500 m), at a sedimentation rate of 0.127 mm/year. The strong block faulting in the basin led to the formation of buried Paleozoic hills, which controlled many overlapping Tertiary structures. Almost 90 of the known oil reservoirs are in these structures. Gu-Dao oil field produces from one of the late Tertiary overlapping structures which is cut along the north and south side by two faults striking nearly east-west. These faults controlled the origin and the development of the comparatively intact structure. A long period of faulting caused vertical migration of large quantities of oil and gas, and the formation of a series of multiple pays. The hydrocarbons are distinctly zoned. That is, in the Paleozoic and lower Tertiary rocks, they are high-paraffin crude oil of high wax and low sulfur content. The upper Tertiary rocks contain highly viscous aromatic-cycle alkane crude oil of low wax, high sulfur content, and dry gas occurs in the upper part of the Neogene and Quaternary. The analysis of the data shows that hydrocarbons are derived from the same source rock--the lacustrine lower Tertiary Sha-He-Jie formation--distributed in the depression surrounding the Gu-Dao structure. A secondary reservoir was formed along the faults during the multiple tectonic movement during the late Tertiary, as a result of the upward migration of hydrocarbons from lower Tertiary rocks. Hence the Gu-Dao oil field is a combination of both primary and secondary reservoirs. The main oil-bearing formation in the Gu-Dao oil field, the upper Tertiary Guan-Tao formation, comprises a set of fluvial deposits, with channel sand bodies as the principal reservoirs. The reservoir extends along the long axis of the Gu-Dao structure, and constitutes the major producing area. The oil field was discovered in 1968 and full production was begun in 1971. The development policy of water flooding at an early stage, either internally, separately, or quantitatively, was adopted according to reservoir characteristics of high viscosity, sand-out, or differences in pays. A series of measures has been taken to control sand and to reduce viscosity. Although 7 years have elapsed since the beginning of production, present oil production per well is equivalent to that of the early stage, a rising trend in productivity is obvious, and good development effects are insured. End_of_Article - Last_Page 698------------

The Charco Redondo Thermal Recovery Pilot

A highly instrumented reservoir was steamflooded in 1965 to determine heat losses, formation heat content, location of formation and injected fluids with time, and residual oil saturation. Predicted heat losses were comparable with those determined from field data. The results of a subsequent successful effort to ignite this reservoir following the steamflood also are presented. Introduction Thermal recovery methods are used to improve production of heavy viscous crude oils. Steamflooding and production of heavy viscous crude oils. Steamflooding and fireflooding are two methods that have been used extensively throughout the industry. In either application, prediction of reservoir behavior is necessary so cost prediction of reservoir behavior is necessary so cost estimates can be made. In 1965 Bellaire Research Laboratories conducted a fully instrumented pilot steamflood in the Charco Redondo field, Zapata County, Tex. This pilot was followed by an in-situ combustion experiment pilot was followed by an in-situ combustion experiment in the same pattern early in 1966. The paper is divided into two parts. Phase 1 describes the steamflood, conducted to determine heat losses, location of injected fluids with time, and the residual oil saturations. Phase 2 describes the in-situ combustion experiment, conducted to determine if residual oil saturations following a steamflood were adequate to support combustion. Phase 1 - Steamflood Phase 1 - Steamflood Reservoir Properties Reservoir properties are itemized in Table 1. Pattern Pattern As shown in Fig. 1, a 1.01 ha (2.5 acre) isolated inverted five-spot pattern was selected. Injector 111 and Producers 112, 113, and 114 were drilled to complete the pattern Producers 112, 113, and 114 were drilled to complete the pattern in conjunction with existing Well 84. The sides of the square pattern were 100.6 m (330 ft). Producer and Injector Completions Producer and Injector Completions The producers were completed in 20-cm (77/8 in.) holes with 14-cm (51/2 in.) OD casing cemented in place with high-temperature cement. All were completed with slotted liners and canvas packers. Each contained 8.3-cm (2 7/8 in.) perforated tubing with a mud anchor and a high-temperature bottom-hole pump. Since the depths were shallow (Table 1), no special provisions were needed for casing expansion. The injector was completed with 18-cm (7 in.) OD casing set to the formation top using high-temperature cement. A 15-cm (6 in.) OD hole was drilled to 0.61 m (2 ft) below the formation bottom with a 14-cm (5 1/2 in.) OD slotted liner set to this depth. Open-end injection tubing 7.6 cm (3 in.) was positioned at the bottom of the interval. No packer was used and no special provisions were made for casing expansion other than a swivel connection at the surface where the steam line joined the tubing. Monitor Array and Completions Twenty-nine monitor wells were positioned in concentric rings around the injector, as shown in Fig. 1. The rings were located at radii of 15.2 (50 ft), 35.0 (115 ft), 50.3 (165 ft), and 65.1 m (220 ft) from Injector 111. The wells located on these rings were on four major azimuths drawn from the injector to the producers and on four intermediate azimuths. Cored locations are indicated in Fig. 1. JPT P. 1522

Stability of Moving Combustion Fronts in Porous Media

Abstract The stability of moving combustion fronts during underground combustion processes is analyzed. The behavior of small deformations in front configuration is studied using knew stability theory and relatively simple models of the combustion processes. In this way, the main physical phenomena that influence stability can be physical phenomena that influence stability can be distinguished clearly. For wet combustion processes, where both air and water are injected, front stability is affected, not only by the ratio of the mobilities of fluids flowing ahead of and behind the front, but also by heat transport near the front and by expansion accompanying vaporization of water at the front. Even more interesting is a "reverse mobility" effect predicted by the analysis. Under some conditions at relatively high air to water injection ratios, fluid flow, and the heat produced by combustion interact in such a way that normally "favorable" mobility ratios become unfavorable. That is, existence of a low mobility in the region of two-phase flow of air and water behind the front actually can promote front instability. For dry combustion the beat transport and reverse mobility effects on stability do not occur and the combustion fronts are typically neither highly stable nor highly unstable; That is, the effective mobility ratio is near unity. Introduction Thermal processes, such as underground combustion and steam drive, are prime candidates for supplementing primary recovery techniques in reservoirs containing highly viscous crude oils. Thermal methods also have been considered for tertiary recovery of lighter oils. Chemical flooding seems currently to be the preferred process, however, for this latter application. As is true for all recovery schemes, the over-all effectiveness of thermal processes depends on the injected fluids contacting a substantial portion of the reservoir, that is, on achieving good sweep efficiency. Of course, the amount of the reservoir swept depends on various factors, including reservoir heterogeneity and the pattern of wells. But studying the stability of moving displacement fronts in an idealized homogeneous porous medium provides useful information that, at a minimum, provides useful information that, at a minimum, gives a qualitative idea of what to expect in more complex situations. For example, if the front is unstable even in the simple case of a homogeneous medium, sweep efficiency is likely to be poor for any realistic reservoir conditions. It has been known for some years that a ratio between the mobilities () of displacing and displaced fluids that exceeds unity gives rise to a destabilizing influence on the moving front between them. Only recently has it been shown that other effects on front stability can be equally important during thermal recovery processes. Analysis of a simple situation with steam condensing and displacing water at a moving front indicated that the adverse mobility ratio because of low steam viscosity sometimes could be offset completely by two stabilizing effects. This conclusion is consistent with Baker's laboratory experiments on steam displacement that showed that moving condensation fronts are usually stable. One stabilizing effect at a condensation front is contraction accompanying condensation of a given mass of swam, a process which extracts mechanical energy from the flow. The other effect is heat transport in the water region, where the temperature varies from the saturation temperature at the front to ambient conditions far ahead of the front. The rate of front advance is controlled by the rate of condensation, high front velocities being associated with low condensation rates. The condensation rate, in turn, is limited by the rate at which the latent heat released at the front can be transported into the water. When the front is deformed as shown in Fig. 1 points such as P are exposed to a large amount of cool liquid so that the local heat flux increases. As a result, the local condensation rate increases at P, and the local front velocity decreases there, producing a stabilizing effect. This qualitative explanation of the transport effect on stability is an improvement over that given in the original paper. SPEJ P. 423