Production Rate Of Wells Research Articles

ANALYSIS OF QUALITY OF PERFORATION OF PRODUCTION FORMATIONS BY WELLS WITH HORIZONTAL COMPLETION

The paper presents correlation-regression analysis of the influence of various factors on the oil production rate of wells with horizontal completion. Attempt was taken to create a model of multiple correlation for explaining the combined effect of these factors on production rate. The model allows both predicting with sufficient accuracy rate the production rate of the well based on drilling and completion data with a sufficiently high proportion of accuracy, and ranking various factors according to the degree of their influence on production rate.

Cost-Effective Production Metering and Allocation in a Mature Offshore Oil Field

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 180887, “A Cost-Effective Methodology for Production Metering and Allocation Using Real-Time Virtual Metering in a Mature Offshore Oil Field: A Case Study of the Greater Angostura Field,” by Italo Raffaele Acuna, BHP Billiton, prepared for the 2016 SPE Trinidad and Tobago Section Energy Resources Conference, Port of Spain, Trinidad and Tobago, 13–15 June. The paper has not been peer reviewed. This paper describes how the use of production-modeling tools, coupled with field pressure/temperature-data-acquisition systems and programming software, served as a means to improve production allocation and surveillance on a real-time basis in the Greater Angostura Field. The complete paper discusses a practical approach to obtain accurate real-time well-production rates without the need for purchasing costly flowmeters for each well. It also demonstrates how virtual metering can be used to identify production-optimization opportunities in the production system more readily. Introduction The Greater Angostura Field is located 25 miles offshore Trinidad and Tobago. The field was developed in three phases: Phase 1, which includes the Kairi, Canteen, and Horsts fields; Phase 2, which includes the Aripo gas development; and Phase 3, which was scheduled to have been completed by the second half of 2016. At the time this paper was written, the Angostura development consisted of 21 producers and seven gas injectors. The facilities and gathering system included one manned central-processing platform (CPP), four unmanned well- protector platforms (WPPs), and one gas-export platform (GEP). All wells have dry production trees and are distributed as follows: Canteen 1 (C1) WPP: five producers and two injectors Kairi 1 (K1) WPP: three producers and two injectors Kairi 2 (K2) WPP: nine producers and three injectors Aripo (A) WPP: three producers The production from the wells in each WPP is commingled in each platform’s header and routed as follows: Canteen 1 (C1) WPP: one subsea production flowline to the low-pressure gathering system Kairi (K1) WPP: two subsea production flowlines to either the low-pressure or the high-pressure gathering system Kairi (K2) WPP: two bridge-connected flowlines to either low- or high-pressure gathering system Aripo (A) WPP: one subsea production flowline to GEP The oil produced from C1, K1, and K2 is processed on the CPP and pumped to shore. The gas produced from these three WPPs is distributed to export gas. The production of the Aripo WPP is sent directly to the GEP for sales.

EFFECTIVENESS OF HOME-MADE MOBILE COMPRESSOR UNITS (MCU) USE AT PRODUCTION OF LOW-PRESSURE CENOMANIAN GAS

It is stated that the extension of the profitability period of production in the fields that are currently at final stages of development can be ensured thanks to using the mobile compressor units (MCU). The increase of gas production volumes is achieved through intensification of productive rates of the depleted wells as a result of connection of MCUs to the gas gathering network. This enables to increase the capacity of loops, to reduce wellhead pressure and, consequently, to increase the production rates of wells. This article shows the economic and energy efficiency of the hypothetical introduction of the domestic system MCU TAKAT 64.09 M4 UHL1 at the well cluster of the field Vyngapurovskoye.

A Quantitative Approach To Analyze Fracture-Area Loss in Shale Gas Wells During Field Development and Restimulation

Summary The economic development of shale gas fields requires the reservoir volume to be stimulated by use of multiple hydraulic-fracture stages along the horizontal wellbore. To optimize the gas reserves, the stimulated reservoir volume needs to be maximized; this requires that offset wells be placed as close to the nearby wells as the fracture-stage lengths will allow. When offset or infill wells are drilled adjacent to existing wells, the new well's hydraulic fractures can interfere with or intersect the existing well's fractures; this reduces the existing well's production rate. This apparent fracture-area-loss event has been called a “frac hit(s)”. For various reasons, the operator may need to evaluate the economic impact of the frac hit(s) on the offset well. Likewise, the operator may need to evaluate the refracturing [refract(s)] of a well caused by providing an additional stimulation treatment to a well that should increase the well's gas-production performance. The presented analysis technique applies to either case. A single well-analysis technique that quickly determines the economic impact of frac hit(s) or refrac(s) is presented. Sufficient production data before and after the frac hit or refrac need to be gathered to establish the internal linear transient flow periods on an inverse productivity-index (PI) vs. square-root-of-time plot. This rate-transient-analysis (RTA) technique has a straight line during the early portion of the data after well storage and well cleanup, which indicates an internal linear transient flow period for the prefrac-hit/prerefrac-hit and post-frac-hit/post-refrac data sets. These straight lines ensure that one can apply the RTA to provide the PI and, thus, the effective fracture areas, Af1 and Af2 or the before and after data sets, as is explained. To verify the accuracy of the RTA results for the fracture-area reduction/gain, a numerical model is made with the known wellbore, fracture stage, and fluid-properties information, and a pressure history match is performed on the prefrac-hit data with historical production data to constrain well-production rates along with the fracture length that provide the determined effective fracture area. By use of the Af1 and Af2 values from the RTA analysis, a pressure match is achieved for the before and after frac-hit data. This verifies that the analytic RTA model provides good results for the fracture-area change caused by the frac hit. One can forecast either a stochastic analytic model (Miller et al. 2010; Miller 2014) or the history-matched numerical model for several years with the field-operating conditions. With this matched model, one can add the post-frac-hit data, and one can achieve a pressure history match by adjusting the effective fracture area. One also can forecast this history-matched model for several years, and one can use the prefrac-hit and post-frac-hit/refrac forecast results to estimate the financial impact of the frac hit/refrac. The single-well-analysis work flow is demonstrated with smoothed data that are based on a real frac-hit well. This simplifies the work-flow demonstration. A sensitivity analysis was run to determine the effect of reservoir permeability on a frac hit. The results show that it has a very large impact at low permeability (<25 nd). At 10 nd, a percentage loss of net present value (NPV) is the same as a percentage loss of fracture area (i.e., a 75% loss in frac area will give approximately a 75% loss in NPV). At high reservoir permeabilities (>100 nd), the impact of a frac hit is tempered because of more flow from the matrix. It is shown that fracture geometry (variation in the fracture-stage lengths) does not greatly affect the results to determine the fracture-area reduction caused by a frac hit. A huge benefit of following the suggested work flow is that the RTA results provide limiting estimates of the reservoir permeability and fracture area that will save significant time history matching the prefrac-hit- and post-frac-hit data sets.

Laboratory-Scale-Model Testing of Well Stimulation by Use of Mechanical-Impulse Hydraulic Fracturing

Summary Reservoir stimulation is commonly used to increase well-production rates and enable economic oil and gas recovery from conventional and unconventional reservoirs. One potential stimulation method that has been laboratory tested as a means to increase well injectivity after conventional hydraulic fracturing is mechanical-impulse hydraulic fracturing (MIHF). MIHF is a high-strain-rate stimulation method that uses a mechanical-energy source as an alternative to rapid gas expansion. Field-scale viability of MIHF was evaluated by use of elastic mechanics and thermodynamics. Results from laboratory tests are presented in which associated flow data indicated significant increases to well injectivity after MIHF stimulation. Tests were performed in two granite specimens with dimensions of 300×300×240 mm3 and 300×300×300 mm3, respectively. The first specimen was unconfined at room-temperature conditions, whereas the second was subjected to heating and true-triaxial confinement. Stimulated well injectivity was evaluated with a series of step-constant-pressure and step-constant-flow injection tests.

Intelligent-Field Management: Monitoring and Optimization of the Greater Ekofisk Area

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 150424, ’Intelligent-Field Management: Real-Time Monitoring and Proactive Optimization of the Greater Ekofisk Area,’ by Amit Madahar and Alannah McIntosh, Weatherford Production Optimization; Ilnur Mustafin, ConocoPhillips; and Nick McAlonan, SPE, Weatherford Production Optimization, prepared for the 2012 SPE Intelligent Energy International, Utrecht, The Netherlands, 27-29 March. The paper has not been peer reviewed. An online real-time production-optimization and monitoring system for the greater Ekofisk area (GEA) of Norway was installed in 2006. The system has evolved significantly since installation, with changes driven by multidisciplinary teams in coordination with the operator’s Production Optimization Centre (POC). This online system integrates data from the complete production system—reservoir to export meters. The system enables real-time monitoring of all wells and their associated instrumentation parameters along with field three-phase production allocated to the well level. The system alerts engineers when a well’s performance is outside predefined tolerances, thereby enabling continuous optimization of the combined field network. Introduction The GEA has a high level of activity in terms of well intervention and drilling programs. Therefore, communication about the current operation status across a large multifunctional organization is essential. The GEA has only three fiscal-metering points to measure production. Although sufficient for production allocation at the field level, it results in uncertainty at the platform level. This situation could lead to lost production-enhancement and optimization opportunities. The POC, subsurface-production-delivery, and reservoir-optimization teams are tasked with assessing real-time data from, nominally, 160 active producers and injectors to minimize losses and maximize field production. An important function of the asset team is to provide daily reports for wells and topside losses. It usually is difficult to compile this information accurately in a short time frame. Most GEA production wells use gas lift; therefore, it is important to use the finite lift gas efficiently. This optimization process uses an asset-network model. If the asset-network model is not updated frequently and maintained, it will lose its ability to predict well-production rates and pressure drops in the system accurately. To resolve these problems, the asset uses a multidisciplinary tool called intelligent daily operations. It is used as a real-time-monitoring tool within the POC and is used for daily well-performance monitoring by the production-delivery engineers. This tool facilitates daily well-production variance to detect under-performing wells and flag production-optimization and well-service opportunities. It provides automatic updates to the network model. The real-time-monitoring tool implements various workflows to enable the different departments to collaborate and share the most-up-to-date information and removes the large amount of manual effort in gathering and analyzing the data, thus allowing engineers to concentrate on increasing production and minimizing losses.

Performance Evaluation of a Mature Miscible Gasflood at Prudhoe Bay

Summary This paper summarizes the acquisition, conventional and compositional core analysis, and reservoir-simulation history match of a core taken roughly 300 ft from a production well in the most mature area of the Prudhoe Bay Miscible Gas Project (PBMGP). Compositional analysis of the core yielded a great deal of in-situ enhanced oil recovery (EOR) performance data and provided insights that could not be obtained from routine core analysis or production data. Fine-gridded reservoir simulations yielded a good match of the offset well-production rates and the observed compositional behavior of the core. The simulations and core data showed a complex layered displacement with alternating intervals of stripped and enriched oil. The data showed that roughly 70% of the cumulative EOR came from reducing the residual oil saturation near the injection well. The remaining 30% was caused by oil swelling.

TECHNICAL CHALLENGES IN THE DEVELOPMENT OF UNCONVENTIONAL GAS RESOURCES IN AUSTRALIA

Unconventional gas resources, defined as low- permeability sandstone, coal seam and naturally- fractured shale gas reservoirs, represent a huge potential resource for future natural gas supply in Australia and around the world. Because low individual well-production rates are often the norm, unconventional reservoir development may involve the drilling of hundreds of wells to make the economics attractive. Thus, careful planning, sound development strategies and cost control are critical for project success.Virtually all unconventional gas resources must be stimulated to be economic; stimulation costs are often the most significant amount of the total well expenditure. Thus, a cost-effective method for reservoir characterisation and fracture treatment optimisation is required. Because of marginal economics, techniques used to analyse the process and results are often oversimplified; this can lead to confusing or inadequate descriptions of the complex behavior of a hydraulically-fractured, low- permeability reservoir and in some cases bad development decisions. Detailed data collection programs and fracture treatment optimisation strategies are essential to adequately address the technical issues involved in unconventional reservoir development.Besides the technical challenges associated with unconventional gas development, good forethought is necessary as to the planning and execution of the overall project. The development scenarios for coal seam and low-permeability sandstone gas resources are highly statistical and succeed or fail based on the average performance of the group of wells within the project. Following proven guidelines and methods during development while integrating key technologies into the planning and optimisation process are essential for success in unconventional reservoir development.

Productivity enhancement in hydrofractured oil reservoirs

Low permeability formations are often hydrofractured to increase the production rate of oil and gas. This process creates a thin, but highly permeable, fracture which provides an easy path for oil and gas to flow through the reservoir to the borehole. Here we examine the payoff of hydrofracturing by determining the increased production rate of a hydrofractured well. We find explicit formulas for the steady production rate in the three regimes of small, intermediate, and large (dimensionless) fracture conductivities. Previously, only the formula for the large fracture conductivity case was known.We assume that Darcy flow pertains throughout the reservoir. Then, the steady fluid flow through the reservoir is governed by Laplace's equation with a second-order boundary condition along the fracture. We first analyze this boundary value problem for the case of small fracture conductivities. An explicit formula for the production rate is obtained for this case, essentially by combining singular perturbation methods with spectral methods in a function space which places the second-order boundary condition on the same footing as Laplace's equation. Next, we re-cast Laplace's equation as a variational principle which has the second-order boundary condition as its natural boundary condition. This allows us to use simple trial functions to derive accurate estimates of the production rate in the intermediate conductivity case. Then, an asymptotic analysis is used to find the production rate for the large fracture conductivity case. Finally, the asymptotic and variationally-derived production rate formulasare compared to exact values of the production rate, which have been obtained numerically.It may be feasible to create more than a single fracture about a borehole. So we also develop similar asymptotic and variational formulas for the production rate of a well with multiple fractures.

On-Site Quality Control of Fracture Treatments

Summary Hydraulic fracturing is widely used within the petroleum industry to stimulate production rates of wells. The effectiveness of these stimulation treatments depends on the selection of the proper materials to maximize the stimulation effect. Once proper materials are selected, use of substandard materials on site in the hydraulic fracture treatment can reduce the effectiveness of the treatment. We developed a procedure for field monitoring and for evaluating the quality of the materials used in stimulation treatments. The program consists of on-site quality-control checks for water quality, gelled fracturing fluids, proppants, and other additives commonly used in stimulation treatments. A field kit and manual support the program. Often, these on-site quality-control procedures reveal deficiencies that were corrected before a treatment was initiated. If these deficiencies had not been corrected, the treatments may have prematurely terminated and/or the stimulation that resulted from the prematurely terminated and/or the stimulation that resulted from the treatment may have been diminished. Introduction An analysis of service company charges for acidizing and fracturing treatments performed in 1983 indicated that bidding resulted in a 39% savings in the cost of stimulation treatments when compared with list prices. Realization of the magnitude of savings achieved from bidding generated some concern regarding the quality of the product being delivered to location. Chevron's West Texas Div. product being delivered to location. Chevron's West Texas Div. requested and funded the development of a fracturing quality-control program with an overall goal to achieve savings through bidding program with an overall goal to achieve savings through bidding without sacrificing quality. Our well stimulation treatments are generally designed by production engineers. Service companies are then asked to bid on the production engineers. Service companies are then asked to bid on the treatments based on these designs. This process of developing our own treatment designs significantly improved results of stimulation treatments and allowed uniform bidding by service companies. Each service company bids on the same type and amounts of fluids, proppants, hydraulic horsepower, etc. proppants, hydraulic horsepower, etc. To remove further bias from the bidding process and to ensure that a satisfactory product is delivered at the well site, a quality-control program was developed. The objectives of this quality control program areto maximize the productivities of wells that are stimulated,to inform the service companies of management's interest in obtaining quality service and materials,to evaluate service companies fairly so that substandard performance can be eliminated and superior performance encouraged,to obtain feedback from the service companies on how to improve quality of well treatments, andto increase our knowledge of the fracturing process. A viable quality-control program requires adequate evaluation of all stages involved in the treatment. For fracturing treatments, this often begins with the primary cementing program and can include openhole logging, perforating, perforation breakdown, fracturing-fluid tank inspection, water-source evaluation, proppant supplier evaluation, proppant evaluation on location, and evaluation of the service company equipment and personnel performance during the treatment. The cementing, openhole logging, and perforating programs are beyond the scope of this paper. Proper quality control requires an additional engineer whose sole responsibility is to monitor materials, equipment, and personnel performance for the entire job. The effort to obtain improved quality performance for the entire job. The effort to obtain improved quality increases treatment costs, but these costs are usually insignificant compared with the increased productivities of the wells over their producing lives. By having an engineer with the quality-control producing lives. By having an engineer with the quality-control re-sponsibility on location, the other engineer monitoring the job is free to evaluate pressure and rate responses during the job properly and to make any changes in the job procedure dictated by the formation's behavior during the fracturing process. Quality control is a cooperative effort between the service company and the production company designed to improve continually or to upgrade the stimulation service provided on location. Through this cooperative effort, problems can be identified and solutions formulated to enhance overall stimulation success.

多層アンカー仕上げ坑井の産量推定シミュレーター

The deposits of Minami Kanto gas field is very thick and reserves amout of methane and iodine. Production wells are completed with long perforated pipes. Most of these wells are tubingless and the artificial lift method is continuous gas lift.I have developed a simulator which is formed with a three dimensional, two-phase double porosity reservoir model and a gas lift program. Using this simulator, production rates of wells can be predicted and production tests are analized exactly.

Estimation of Formation Strength From the Mechanical-Properties Log(incudes associated paper 6400 )

The mechanical-properties log provides a quantitative means for identifyingsands that are strong enough to produce oil and gas without any form ofsand control. The method is based on a correlation of in-situ strengthwith the dynamic elastic moduli computed from sonic and density logs. Introduction To meet current demands for more oil and gas, companies would like to increase production. However, increases in well-production rates are frequentlyaccompanied by sanding problems. For this reason, there is often reluctance to go to higher producingrates.Yet many sands are, in fact, strong enough topermit greater production. It would be highly beneficialto be able to recognize these. It is also important toknow beforehand which sands are too weak to beproduced at the higher rates because once the wellhas made sand, consolidation is difficult and oftenineffective.Many factors must be considered to understandthe sanding problem. The pressure gradient near theperforation, the flow rate per foot, and the scrubbingaction of the fluid being produced all interact toimpose destructive forces on the sand. The ability ofthe sand to withstand these destructive forces isdetermined by two main factors: the intrinsic strengthof the formation, and the capability of the sand toform stable arches around the perforations.The intrinsic formation strength is governed bythe state of the confining stress (as determined bythe difference between the overburden stress and thepore pressure), the grain shape and sorting, and thecementation between the grains. Shaliness maycontribute to the cementation.There is a good correlation between theformations intrinsic strength and the ability of theformation to produce at a high flow rate. Moreover, the consistently lower permeabilities of the strong sandslimit the magnitudes of the flow rates to which theyare exposed. Conversely, weak sands have relativelyhigh permeabilities and are capable of producing athigh flow rates, even with small drawdowns. Forthese, sanding is a potential danger.Although we believe that a criterion based on theintrinsic strength is basic and fundamental, there areother factors that cannot be ignored. For instance, the type of fluid being produced is important. Ourexperience to date has been predominantly with gasand oil production, but it is believed that productionwith a high water cut may require higher intrinsicstrength.Resistance to sanding in a weakly cemented sandcan result from the formation of a stable, load-carryingsand arch spanning the producing cavity. In this respect, published work on laboratory experimentsindicates that the presence of two different fluids(e.g., oil and water) in the formation, with the wetting-phase saturation near irreducible, maycontribute cohesive forces between the sand grains.These forces help sustain a stable arch after some sanding has occurred. The forces result from theinterfacial tension between the two fluids where theirsurface contacts the sand grains, and the effect is topull the sand grains together. JPT P. 283^

The Effect of Induced Vertically-Oriented Fractures on Five-Spot Sweep Efficiency

Abstract Substantial evidence indicates that many petroleum producing horizons contain naturally occurring, ordered fracture systems and that within a particular geologic zone, vertical fractures induced in wellbores often will be directed along a particular compass direction. Both conditions will seriously alter the fluid displacement behavior within reservoirs. In this study the effect of induced fracture orientation and length on sweep efficiency is determined for a five-spot pattern. In general, it is assumed that all wells are fractured and directed along the same compass direction. Using the electrical analog to steady state, two-dimensional fluid flow in porous media, boundary conditions are obtained from which flood fronts are tracked numerically. The numerical computations require a particle tracking routine for approximating flood front histories. It is shown that recovery is sensitive to the length and orientation of fractures for the pattern studied. With the proper design of fracture-pattern systems, recovery can be enhanced considerably. Introduction Hydraulic fracturing introduced in 1949, gave the industry a rather inexpensive means of increasing the fluid injection or production capacity of wells. It has been used with particular success to increase the production rate of wells completed in tight formations, such as in western Pennsylvania where producers have fractured in depleted or near-depleted fields and observed economic responses. Once the natural energy declines in such a reservoir where all wells have been fractured, waterflooding is generally suggested as means of further increasing recovery. Of the dual objective sought in waterflooding -- high injectivity and high break-through sweep efficiency - the former condition can be obtained if all wells in the flood pattern are fractured; the latter condition should depend on the nature of the fracture system. Considerable theoretical work has been published on the nature of fractures induced in boreholes. Although discussion persists concerning the possibility of forming a horizontal at a given point within the wellbore, it is generally conceded that only vertical fractures will develop below a given depth, i.e., where the fracturing pressure is less than the overburden load. Given the fact that fractures will be vertical in most cases of interest, it is also important to know whether there is order to fracture orientations within a given geological region. Kehle has suggested that in tectonically relaxed areas of uncomplicated geology, the stresses are fairly uniform and all fractures in the region should be parallel. Dunlap arrived at a similar conclusion in a theoretical investigation of localized stress conditions surrounding the borehole. He concluded that most vertical fractures are propagated in a preferred azimuthal direction. Fraser and Pettitt, in extending these theoretical suggestions to a specific field case, used an impression packer to record both a vertical fracture and the orientation of this fracture in the wellbore of a well in the Howard Glasscock field, Tex. Use of this information enhanced the waterflood recovery of the field. Anderson and Stahl also used impression packers on three fractured wells in the Allegheny field, N. Y., and found that the fractures were oriented more or less along the same compass direction. Orientation of the fractures in this manner depends on the stress condition within the formation during fracturing. Elkins and Skov have demonstrated that a natural, oriented, vertical fracture system exists within the Spraberry field. SPEJ P. 260ˆ

Steam-Drive Project in the Schoonebeek Field, The Netherlands

Abstract In Sept., 1960, a steam-drive project was started in the solution-gas drive area of the Schoonebeek field. A pattern of three five-spots and one four-spot was selected covering an area of 65 acres. The pay in the project area has good lateral continuity and dips slightly to the northeast; it is about 80 it thick and permeability increases from 1,000 md at the bottom to approximately 10,000 md at the top. The oil originally in place was 12.6 X 10 bbl. The oil has an in situ viscosity of about 180 cp. At the start of the steam drive the cumulative primary production due to solution-gas drive amounted to 4 percent of the oil originally in place. Reservoir pressure had dropped to about 120 psi and no significant primary reserves remained. Some 113 million bbl of steam (all steam quantities are expressed in barrels of water vaporized) have been injected, resulting in production of an additional 4.1 X 10 bbl of oil, or 33 percent of the oil originally in place. This corresponds to a cumulative oil-steam ratio of 0.37 bbl/bbl. It appears that the steam preferentially moves updip while liquids are produced mainly from downdip wells. Observations indicate that the steam flows through only the upper part of the formation. The lateral steam distribution in the pattern is unsatisfactory since several production wells hardly reacted and, hence, contributed little lo the oil production. Production performance and results from material balance calculations agree satisfactorily with the results of large-scale laboratory experiments. On the basis of these experimental results the steam drive, together with a cold water follow-up, is expected to bring ultimate recovery to a value of at least 50 percent of the oil originally in place. No serious production problems have been encountered. However, due to mechanical failure, two old production wells and one injection well had to be replaced. An extension of the steam drive in this area is, under construction. Introduction The Schoonebeek oil field, discovered in 1943 and developed after World War II, is situated in the eastern part of the Netherlands. The main oil reservoir in this field is the Valanginian sand. A completely sealing fault divides this reservoir into two areas (Fig. 1): the southwestern part of the sand body where primary production is obtained by means of a solution-gas drive, and the remainder where edge-water drive is the production mechanism. In the greater part of the field the reservoir consists of a single, unconsolidated sand body. The net thickness ranges from 30 to 100 ft and the top is between 2,400 and 2,800 ft below sea level. Formation permeability varies from approximately 10,000 md at the top to values of the order of 1,000 md at the bottom, and porosity is about 30 percent. The reservoir contains a paraffinic oil of 25 deg. API gravity with an in situ viscosity of 160 to 180 cp. Initial oil saturation was high (85 to 90 percent). The relatively large quantity of oil in place (more than 10' bbl), and the low ultimate primary recoveries expected from this field -approximately 15 percent stock-tank oil initially in place (STOIIP) for the water-drive area and 5 percent STOIIP for the solution-gas drive area - clearly indicate ample scope for secondary recovery. Because reservoir and crude characteristics made this field suitable for thermal secondary recovery, a hot-water drive project was started in the water-drive area about 10 years ago. A few years later a steam drive and an in situ combustion project were started in the solution-gas drive area. This paper deals with the performance of the steam-drive project, which was started in Sept., 1960, and which is still in operation.