This paper presents a method of estimating the reliability and expected operating time for injection units. An analysis of failure observations is presented and the means by which statistical methods can be employed to obtain reliability estimates. Expected operating times incorporating repair periods are developed and an example presented to illustrate the application of these techniques.

Effective waterflooding requires that injected water be condifed to and moved through the zones of permeability containing the remaining oil in place after primary production. The injection waters available for waterflooding are becoming more and more limited; therefore, this supply must be more efficiently utilized through confinement to the zones containing the secondary oil-in-place. Problems which are most common to water injection wells are those effecting confinement of injection water; i.e., channeling up or down out of zone, channeling through existing water stringers, or excessively high permeability zones, and simply going out bottom. Several different materials and methods are being used in efforts to control these water injection problems

The economics of secondary recovery is certainly important to today's domestic oil industry. There is, however, another important consideration which must be taken, in view of present shortages of proven reserves-ultimate recovery of secondary oil. In other words, can more of these known reserves now in place in reservoirs already drilled and under waterflood be produced economically? Obviously, no oil will be banked to a producer if no water is injected into the section containing the moveable oil saturation which remains after primary production is accomplished. There are three common problems encountered in waterflooding which make it difficult even impossible-to inject water into and through all of the reservoir containing the residual moveable oil: 1. Little or no response to injection due to lack of confinement to the section of interest 2. Premature water breakthrough due to zones of high water saturation or extreme variations of permeability within the section of interest 3. Water breakthrough due to fingering of injection fluid caused by over-injection and/or directional permeability within the section of interest. This paper will consider only problems 2 and 3. Problem 1 was discussed by the author in a previous short course (1971). Water breakthrough occurs rapidly in zones of high water saturation since injection always seeks the path of least resistance. High water saturations offer less resistance to the flood water because the relative permeability to water is greater. Water breakthrough occurs rapidly in thin zones of high permeability for two reasons: 1. Most of the primary oil comes from the higher permeability, leaving high water saturation. 2. The extremely high permeability zones offer less resistance to the injection water anyway. Water breakthrough comes soon when over-injection causes water to finger through to producers. Over-injection occurs when an optimum rate is calculated for a total section to be flooded and only a small zone accepts the injected fluid-again the path of least resistance. Directional permeability simply offers the shortest distance between two points-in this case, between the injection and producing wells. The paths of injection flow after breakthrough become even easier since they exhibit higher relative permeability to water.

This presentation discusses the results of experimental and field case studies of a remedial treatment technique designed to eliminate fracture proppant production. This process uses a low-viscosity consolidating agent, which is placed into the propped fractures via coiled tubing or conventional tubing coupled with a pressure-pulsing tool. The treatment fluids are designed to provide consolidation for previously placed proppant near the wellbore without damaging the permeability of the proppant pack. The consolidation treatment transforms the loosely packed proppant in the fractures and the formation sand close to the wellbore into a cohesive, consolidated, yet highly permeable pack. Laboratory gas flow testing indicates that the proppant pack in a fracture model under closure stress required low-strength bonds between proppant grains to withstand high production flow rates. Field case histories are presented to discuss treatment procedures, precautions, and recommendations for implementing the treatment process. One major advantage of this new remedial treatment technique is the ability to place the treatment fluid into the propped fractures, regardless of the number of perforation intervals and their lengths, without mechanical isolation between the intervals. The fluid placement efficiency of this process makes remediation economically feasible, especially in wells with marginally economic reserves.

Remote production management systems involve several basic configuration components. These components can be thought of as building blocks comprising a system. For the purpose of our discussion we will represent or conceptualize major components and their respective detailed facilities by means of block diagrams.

Modern stimulation treatments involve recording of a variety of data including surface rates, wellhead pressures, liquid additive rates and other parameters related to the fluids and proppants being applied as shown in Fig. 1 8, 2. In recent years, computers have been used not only to track and evaluate such treatments but also to model bottom-hole conditions in an attempt to simulate fracture geometry in real time during the treatment. Much of this work has centered around three dimensional models such as noted by Meyer1j2 and Cleary3. The capabilities exists that we can now read data directly into one or more of these new models via remote telecommunications real-time, offering a great savings in time and manpower. The proper utilization of fracture simulation software requires personnel capable of running and interpreting these highly specialized programs. Making such personnel available on location can be costly and is not always possible. Remote telecommunication of real-time data can serve a useful purpose in this regard. Telecommunication of data offers a major benefit to operators by providing the ability to monitor treatments remotely and observe the analysis as it is being performed real-time. Personnel at the remote site may also analyze the data in real-time and provide guidance over the phone.

This paper will discuss a method for the success till removal of scale deposits and perforation damage that inhibit the productivity/injectability of a well by the usage of a downhole tool that creates low frequency (16-40 Hz) oscillations in the wellbore fluid. Other methods for addressing the problem of scale and perforation damage will be discussed with a comparison of how and why this method proves to be more effective.

Iron sulfide scales vary in composition; this paper, in three parts, describes how a thorough analysis of the scale is necessary to optimize the chemical treatment and successfully remove the damage. The first part describes the different types and compositions of iron sulfide scale and the need for a tubing cleanout prior to an acidizing treatment. The second part describes the detailed analysis of the scale through the use of quantitative X-ray diffraction analysis and elemental analysis by energy dispersive X-ray. The third part of this paper presents scale removal treatment case histories.

Optimising the recovery of hydrocarbons has led to an increasing need for remedial applications in both production and injection wells. The increasing use of multi-zone horizontal completions, both for shale and more traditional formations, means thousands of frac ports are now being run every year. In 2010 a new technology was launched in North America to expand stainless steel patches using a high pressure inflatable packer. This has now become a regular service, both for perforation shut-off and casing repair. The versatility of the technology has also enabled it to be used to seal leaking cementors and frac ports, with the unique ability of creating a high pressure resistant inner lining and yet enabling the passage of large size balls to activate the ports below. This paper will describe rapidly how the technology works and follow up on the progress made over the last year. The first US operations base has been set up in Midland, Texas. Some of the first US field applications including both casing repair and perforation shut-off will be described. The paper will also present the testing process to validate using the Patch with differential pressures up to 10,000 psi, and describe the first field operations repairing frac ports. It will conclude by presenting the development of possible future applications of expandable stainless steel for improving completions

Converting beam pumping wells to plunger lift drastically cuts costs, improves profit. and keeps marginal producers profitable. This paper discusses one such case for a West Texas Field. The majority of the wells converted to plunger lift showed equal or more oil and gas production after the conversion. Some of the wells increased gas production by almost 2009/o. Twenty-one wells (11% of the total number of wells) have currently been converted to plunger lift. Saving chemical treatments both for corrosion and paraffin, Other benefits include reducing failures, eliminating rod pump repairs, rod parts, electrical costs and reducing environmental liabilities such as stuffing box leaks. Other savings include an increase in the return on capital employed (ROCE) by removing surplus equipment from inventory. The sale of surplus equipment pays for at least two plunger lift systems. This discusses well selection criteria. field results. new technologies in plunger lift operation. and related benefits

The Delaware formations are submarine channel/fan sands that are difficult to characterize. In this study, new methods have been applied to characterize the East Livingston Ridge Delaware Field. Using well logs, a complex 3-D reservoir model, composed of six layers and a meandering channel, was constructed to represent this geological depositional setup. Due to drastic changes in layer lithologies, determining multiple oil/water contacts and water saturations required a detailed well log interpretation. Using core data and well logs, good correlations between log porosity and core porosity have been obtained. Using the obtained porosity at the wells, geostatistics was applied to estimate the areal porosity distribution in each layer. The permeability distribution was derived by using a k-4 correlation obtained from the core data. Since the large-scale 3-D reservoir model: obtained with core data and correlations, does not match the production history, an automatic history matching code was used to estimate large-scale properties. Production rates of the three phases (oil, gas and water) at each of the 23 wells of this study and the reservoir pressure were history matched using a recently developed automatic history matching algorithm. A detailed reservoir description, including the large-scale k-4 correlations, pseudo relative permeability, and other reservoir engineering parameters were estimated in each layer. The conditioned reservoir model was used to investigate several drilling and/or waterflood schemes for future development of the reservoir.

Current drill-stem test pressure-recording techniques rely on a pressure sensor, a chart recorder and a clock. Analysis and interpretation of this recorder data can only be done after the tool string is retrieved from the well. The subject of this paper is a computer-based system that monitors, records, analyzes and displays at the wellsite, supplying the reservoir data necessary for the well operator to make a production decision about the well. This system uses the capabilities of full-opening testing strings to provide instantaneous display of pressure and temperature information at the time intervals selected by the operator. Because the system provides a continuous stream of data (at selected intervals) the printer-plotter can display results of computer calculations and make graphs necessary for evaluation of the reservoir. The well operator can judge by the data received when the test can be terminated, and so could shorten significantly the rig time used for the test. A conventional 'pressure vs. time plot' is made throughout the test, and Horner, Log-Log and 'pressure vs. square root of time plots' are available on operator demand. The well operator can also obtain calculations of the well's theoretical potential at the conclusion of the test or during any flow period after closed-in pressure data accumulate.

The Means field, located in Andrews County, Texas provides an excellent opportunity to observe the evolution of reservoir management to meet changing economic and technical challenges. The Means field was discovered in 1934 and developed on 40-acre [16-ha] spacing. Reservoir management techniques began within one year of discovery and have continued with increasing complexity as operations have changed from primary to secondary to tertiary. In 1963, a major portion of the field was unitized as the Means (San Andres) Unit (MSAU), which will be the subject of this discussion. Several papers have been published describing specific programs for the field. 1,2,3,4,5 This paper describes the evolution of reservoir management at Means on an orderly basis. Reservoir management at Means has consisted of an ongoing but changing surveillance program supplemented with periodic major reservoir studies to evaluate and make changes to the depletion plan. This paper concentrates on reservoir description, infill drilling with pattern modification, and reservoir surveillance. The role of reservoir description is followed from relatively simple techniques in the 1930's to the recent use of high resolution seismic to improve pay correlation between wells. The importance of reservoir continuity in determining well spacing and injection patterns is discussed for both secondary and tertiary operations. Although surveillance has been an integral part of reservoir management in the Means field since discovery, a much more detailed plan was developed for surveillance of the CO2 tertiary project.

The Means field, located in Andrews County, Texas provides an excellent opportunity to observe the evolution of reservoir management to meet changing economic and technical challenges. The Means field was discovered in 1934 and developed on 40-acre [16-ha] spacing. Reservoir management techniques began within one year of discovery and have continued with increasing complexity as operations have changed from primary to secondary to tertiary. In 1963, a major portion of the field was unitized as the Means (San Andres) Unit (MSAU), which will be the subject of this discussion. Several papers have been published describing specific programs for the field. This paper describes the evolution of reservoir management at Means on an orderly basis. Reservoir management at Means has consisted of an ongoing but changing surveillance program supplemented with periodic major reservoir studies to evaluate and make changes to the depletion plan. This paper concentrates on reservoir description, infill drilling with pattern modification, and reservoir surveillance. The role of reservoir description is followed from relatively simple techniques in the 1930's to the recent use of high resolution seismic to improve pay correlation between wells. The importance of reservoir continuity in determining well spacing and injection patterns is discussed for both secondary and tertiary operations. Although surveillance has been an integral part of reservoir management in the Means field since discovery, a much more detailed plan was developed for surveillance of the CO2 tertiary project.

The reservoir average pressure can now be evaluated from routinely available rate and flowing pressure production data, using an extension of the reciprocal productivity index method. Traditionally, reservoir average pressure could only be determined from an extended duration build-up test. Especially in low permeability, stimulated reservoirs, that procedure generally tends to underestimate the pressure, due to practical limitations on shut-in times. In addition, an error in the reservoir average pressure determination results in an error in the computed skin for the well. However, this new procedure provides an independent evaluation of skin and pressure so that they are not dependent on one another. The theory for the method is explained and two example field applications are included.

This paper is concerned with the application of sweep out behavior in estimating oil recovery from hydrocarbon-bearing reservoirs. It reviews the theory of sweep efficiency and related concepts. Parameters studied include the influence of fluid motilities on sweep out performance, the consequential entrapment of oil due to well pattern geometry, permeability-porosity inhomogeneity effects, and results of stratification of the producing zone on sweep out performance. Remedies for some of these problems are suggested. Numerous field examples are cited.

In this paper the chemistry of phenolic resins and the most recent test results are presented to find out the effect that resins may have on the various chemicals in commonly used frac fluids, metal ion crosslinkers, persulfate breakers and foam based fluids. Also, the effects of various coatings and chemical combinations on pH and compressive strengths are examined to arrive at ways to improve the resin coated proppant performance in all types of fluids. Enhanced compatibility resin coated products are now available for use where the effects of fluid interaction could be damaging to the results of the fracturing treatments.

Approximately fifty billion barrels of stock tank oil were originally in place in the larye carbonate reservoirs of the Permian Basin. Two-thirds of this oil occurred in the San Andres and Grayburg strata. Much of the recent work utiliziny carbon dioxide as the miscible displacing fluid has been conducted in San Andres reservoirs, yet other strata may also offer substantial opportunities. Ten to fifteen percent of the original oil-in-place was reported to be in Clearfork or Yeso reservoirs. One of the Clear Clearfork producers in West Texas is the Anton- Irish oil field. The estimated original oil in place was near 500 million barrels. The cumulative production to l/1/84 was 150 million barrels. This leaves more than 300 million barrels of stock tank oil as a possible target for a successful EOK project. If the EOR project should recover as much as fifteen percent of the original oil-in-place this would increase the oil recovery by 75 million barrels of stock tank oil. Hence the purpose of this work was to conduct a laboratory study to determine the response of a Clearfork crude oil to different miscible displacement oil recovery processes. Carbon dioxide yas was used as the displacing fluid on one series of tests, and LPG slugs pushed by nitrogen were used in a second series of tests. This paper reports the results of the study.

Laboratory studies have been made to determine the oil recovery by displacing the Levelland and Wasson crudes by carbon dioxide at various pressures. For the case of the Wasson crude it has been found that a slug of carbon dioxide equal to ten percent of the hydrocarbon pore volume pushed by nitrogen resulted in an oil recovery of 96% of the original oil in place. The use of a slug of carbon dioxide of five percent hydrocarbon pore volume pushed by nitrogen resulted in an oil recovery of 90%. The cost of carbon dioxide brough in from Colorado or New Mexico is expected to be $1.00 to $1.25/MCF. The cost of nitrogen is expected to be less than 50 cents/MCF delivered at high pressure. At Wasson or Levelland reservoir conditions one MCF of nitrogen will occupy three times as much pore space as one MCF of Carbon Dioxide. The cost of nitrogen at reservoir conditions is estimated to be only 15% of the cost of Carbon Dioxide at reservoir conditions. It appears the nitrogen-driven carbon dioxide slug oil-recovery method may have application to various West Texas crudes.

This paper describes a new pumping system for low-volume/marginal oil wells and deliquification of gas wells to extend well life by reducing the economic limit. The economic limit is reduced by decreasing capital, installation, and operating costs of low-volume artificial lift. Many low liquid volume gas wells cannot justify the current cost of artificial lift. Although beam pumping is typically the lowest cost lift method, its inefficiency at low rates requires a much higher lift capacity than the well actually produces and requires a minimum +/- 25 horsepower. This new pumping system can operate on as low as +/- 0.5 horsepower, significantly reducing capital, installation, and operational costs.

This paper presents the results of a successful application of a new-generation polymeric selective water reduction (SWT) that reduces water production without requiring zonal isolation. The SWT can be bullheaded into open intervals without the need for isolating water zones from hydrocarbon zones. As a result of this treatment, the productive life of a well can be extended, with a gradual increase in water cut. This translates to a high potential profitability value for mature fields with a high water cut. It can increase the hydrocarbon recovery percentage in formations that otherwise would be destined for abandonment. Previous papers have discussed the laboratory development of the SWT based upon the use of a hydrophobically modified polymer. This paper will focus upon the field implementation results of this technology. Specifically, this paper will focus upon candidate selection, job design, and summary of the results of treatments performed.

Pumping Solutions Incorporated has developed and tested a new type of Electrical Submersible Pump that uses a positive displacement, hydraulically activated diaphragm pumping mechanism in place of the traditional centrifugal pump. This paper presents the field trial results and lessons learned from over 80 real world field installations in coal bed, conventional gas, and conventional oil wells, with data documenting solids handling, gas characteristics, electrical efficiency, and pump performance. Test results show significant improvements over conventional rod, PCP, centrifugal and other types of artificial lift in solids handling, gas lock characteristics, electrical efficiency, production economics and low volume/deep pump performance. The paper also discusses the issues associated with the use of this new technology, and the basics of the pumping system itself.

This paper discusses field results of a fracture-stimulation treatment that includes a relative-permeability modification (RPM) chemical agent. The design objective was for the RPM to leak off into portions of the created fracture during the stimulation treatment and help prevent water production. Initial treatments were performed in April 1997 in the Brushy Canyon formation in southeastern New Mexico. The selected candidates treated were in the Delaware sand reservoir. Previous fracture treatments in this interval had resulted in water cuts greater than 60%, and the continued production of these wells had been uneconomical because of the presence of damaging scale and a subsequent decline in total fluid production; the water cuts would remain at 60 to 70%, but the total fluid production would decline.

Electronic Downhole Load Cells (DKLC) have been used to quantify rod loadings calculated by predictive and diagnostic wave equation programs. Test results to date show that software calculations agree closely with DHLC measurements. However, there is a difference in how software programs account for buoyant forces which results in discrepancies in reported loads and placement of the zero load line. The overall impact of this difference in the tests run to date. has not been large and may only be critical in the most demanding rod pumping conditions.