In the past decade the number of secondary recovery projects has increased rapidly in the Permian Basin and surrounding area. Water injection is the most popular method of re-energizing reservoirs. As a result, demands on the artificial lift equipment have increased due to higher individual well productivity. In many instances larger equipment has been installed. Two major reasons for replacing beam equipment in the past have been torque limitations and displacement limitations. Torque limits are usually reached prematurely because the unit is being operated in the longest stroke. Displacement, limits are usually defined by an arbitrarily established maximum operating speed. As a result equipment is replaced when, with some modification, it could well have met the increased demands for a prolonged period. The slow, long-stroke pumping method is considered the best method for trouble-free operation of beam units. In the past, operators were able to employ this method because allowables were low and most fields were under primary recovery. As a result, lift equipment was not loaded. Now, with allowable factors up and secondary recovery projects responding, demands placed on lift equipment have increased significantly. Since producing wells are predominately equipped with beam units, ,any improvement in the loading efficiency of these units could result in substantial savings through delayed or unnecessary investment for larger units. One way to achieve this improvement is through the use of the fast, short-stroke pumping method, when applicable. Another way is by controlled overloading of existing equipment.

The necessity and desirability of well stimulation has been apparent for many years. Many wells and fields would not be economical producers without modern completion and stimulation methods. To break this situation down even further, it can be said that where several porous zones are present in a well, each zone will not contribute its maximum production without proper treatment. With these things in mind, our purpose becomes very clear. It is simply to properly stimulate each porous zone or stringer in the pay section. A number of methods have been employed to achieve this selectivity. Among these are packers, bridging plugs, straddle packers, and various forms of gels and other blocking materials. Tubing and packer methods are accompanied by reduced injection rates. Bridge plug methods require more time. Gel and blocking material methods are difficult to evaluate. Any of these approaches to selectivity involve considerable expense.

Pump design, material selection, and corrosion protection are presented as parameters in the selection of sub-surface pumps where pump usage is in a corrosive environment.

For CO2 flood modeling the complex geology at the Pennsylvanian SACROC Unit, new core was obtained by utilizing several new techniques to preserve key features or provide adequate detail on the analysis, including analysis of twelve-inch whole core samples. To maximize the value of new core data for model development and scale-up exercises, a "scale down" exercise was performed on selected samples: twelve inch whole core samples were analyzed then cut into six inch whole cores, two inch whole cores, and selectively plugged. Various analyses were run on each of the smaller steps to quantitatively evaluate the effects of sample size. This analysis shows Kv is sensitive to sample size, and smaller samples tend to overestimate Kv compared to their longer counterparts, especially in ranges less than 10 millidarcies. The modeling implication is that cores analyzed with standard methods may not adequately sample barriers to vertical flow.

Conventional downhole treatments for scale and corrosion typically rely upon either "squeeze" or batch type treatments for control of corrosion and/or scale. These treatments introduce large amounts of inhibitor into the wellbore area and may adversely affect the production characteristics of the well, require excessive amounts of chemical, and require repeated treatments over short periods of time. The use of encapsulated materials for scale and corrosion inhibition has recently been shown to be a reliable and economic alternative to the conventional squeeze or truck batch treatment. Encapsulated materials provide a reliable, long term, controlled release of inhibitor at concentration levels high enough to provide the required protection without introducing potentially damaging chemicals into the formation. This paper details field experiences with the encapsulated materials in a variety of wells and the results that have been obtained with these treatments.

A standard fracturing blender retrofitted with a microprocessor controlled proppant delivery system has been operating in the Odessa, Texas area since May 15, 1986. The speed and control capabilities of the system's microprocessor has allowed fracturing operations incorporating non-standard "ramping" sand concentration schedules to be routinely performed with this blender. Fracturing operations with "stair step" sand concentration schedules have also been completed with this blender. Subject paper presents a case history of fracturing operations performed in West Texas with a microprocessor controlled fracturing blender. Pre-job planning, system operation and blending capabilities of the blender are also discussed. Case history documentation for fracturing operations with ramping sand concentration schedules is presented in the form of strip chart data collected during these operations. Documentation is also presented for a fracturing operation with a stair step sand concentration schedule.

Through the more precise control of the existing laws of physics comes the improvement in efficeincy, and as it follows, his surroundings, his possessions, and inevitably, his future. It is our challenge in this time of falling oil prices, shakey economy, and expected world-wide surprises that we exist. If we could individually improve each of the conditions that shape our future, we would certainly make attempts in that direction. Yet, being only mortals,. (even Arkansas mortals) we must religate our lives to the improvements that we can achieve. One of the greatest tools available to us today is the microprocessor and the derivitive controls which have become available because of its minescule yet vastly powerful existance. It is this small bit of silicon upon which we can impose our greatest wishes, and, if we should happen to use the right "language" combined with the proper "words" we can decree, and it will be done.

Operators drilling in the Permian Basin and surrounding areas with low fracture gradients have long strived to achieve zonal isolation and prevent losses in primary cementing. Solutions generally involved two-stage cementing, water extended lightweight filler cement or foamed cements. Microsphere based cement provides additional solutions to problems associated with low fracture gradients. The addition of lightweight microspheres to cement slurries can create lightweight cement slurries without the early compressive strength development issues associated with water extended lightweight slurries. This allows microsphere cement to be placed across zones of interest as production cement without experiencing losses. Eliminating or minimizing losses helps to ensure zonal isolation with the primary cement job, eliminating the need for remedial work. This paper discusses case histories including both intermediate and production casing strings where these alternative lightweight cementing solutions have been used. Zonal isolation and minimization of annular losses on these wells will be illustrated.

The Mini Massive Frac is a technique designed for stimulating low porosity, low permeability formations. It allows for placing high concentrations of sand in the hydraulically induced fracture by limiting fluid loss. The technique also utilizes crosslinked polysaccharide derivative fracturing fluids to provide a uniform distribution of proppant. Since its' introduction to the Permian Basin, the Mini Massive Frac has been used to treat more than 150 wells, with considerable success. This paper describes the design characteristics of the Mini Massive Frac technique. Emphasis will be given to field case histories showing sustained production increases typical of these treatments. Also discussed is the use of 100 mesh sand for leakoff control, and high viscosity fluids for greater sand carrying capabilities.

Repairing tubing leaks can easily result in the most expensive operating cost incurred in rod pumped wells. Tubing leak repairs are not only expensive but lost revenue from downtime can be significant. The prevention of tubing failures will greatly enhance operating profits from a rod pumping system. This paper will discuss rod buckling, which is one common cause of tubing failures, and how to minimize this problem by adjusting pumping parameters and installing a designed sinker bar section. Methods for designing a proper sinker bar section, utilizing dynamometer surveys and well failure histories, will also be discussed

Equipment failure and it's attendant costs are extremely important in today's petroleum industry. Since Rod Pumping is the predominant means of artificial lift, minimizing equipment failure in rod pumped wells can have a significant impact on profitability. This paper addresses recommendations which have proven successful in the majority of wells. These have been developed within ARC0 over the past 25 years and include equipment selection and design, operation and chemical treatment. The ultimate goal is to address and solve problems on a well by well basis.

Performance predictions of the proposed miscible CO2 injection project for the Wellman Field, Terry County, Texas were made using an enhanced oil recovery process numerical simulator. The study investigated the potential of injecting a relatively small, gravity stable CO2 slug with nitrogen as the drive gas into the crest of the cone-shaped reservoir. The effects of slug size, injection rate and reservoir pressure were evaluated for an optimum future operating plan. The differences in fluid densities at reservoir conditions were conducive to gravity segregation of the nitrogen, CO2 and miscible oil bank. Assuming that most of the produced CO2 would be reinjected, a CO2 slug as small as 15% of the initial hydrocarbon pore volume appeared to be sufficient to mobilize the remaining recoverable oil in-place. Oil production performance during the early years of the project was similar for CO2 injection rates of 10 MMSCF/D and 20 MMSCF/D so the lower rate case appeared economically more attractive. Since the massive carbonate reef, having a vertical oil column of over 800 feet, exhibited no major barriers to impede horizontal or vertical fluid flow, an excellent sweep of the reservoir was predicted in all cases. The results of this study indicated that the concept of the proposed CO2 flood was reasonable and could provide an economic tertiary oil recovery process for the Wellman Field.

Primary oil recovery frequently results in oil recoveries of only 10 to 20 percent of the original oil in place. Several hydrocarbon miscible methods have been tested and proven successful as a secondary or tertiary method of oil recovery under certain reservoir conditions."2"3 Wide application of these methods has been limited by economic factors. Hydrocarbon miscible displacement had its beginning with high-pressure natural-gas injection more than 25 years ago.4 Complete miscible displacement results in the displacement of one fluid by another with the lack of a phase boundary between the two fluids. Natural gas injection was followed by other miscible displacement methods using LPG slugs, enriched gas, and COz. With the increasing cost of these gases, it appeared desirable to study the feasibility of oil recovery by use of high pressure nitrogen injection.

The world's first large-scale miscible displacement project by high-pressure gas injection has produced 130,000,000 bbl, almost double the original estimated primary recovery of 69,000,OOO bbl, at the University Block 31 field in Crane County, Tex. Early injection-production history is shown on Fig. 1. The field-wide project began in 1952, and will keep the unit on stream well into the future, with ultimate recovery efficiency estimated at 60%. Infill drilling has helped boost daily production to 16,000 bbl, highest producing rate since gas injection began in 1949. Atlantic Richfield (formerly The Atlantic Refining Co.) discovered Block 31 in 1945. Operators agreed to reinject produced gas into the Devonian reservoir in 1949 for partial pressure maintenance. The field was unitized in August, 1952, with Atlantic Richfield as the unit operator. Others include Phillips Petroleum Co., Champlin Petroleum Co., and Continental Oil Co. Extensive research indicated that oil recovery could be improved substantially by miscible displacement through high-pressure gas injection. Waterflooding was impractical because of the low permeability of the Devonian formation. The reservoir contains five producing horizons, of which the Devonian at 8500 ft is dominant. The miscible project, which began in 1952, includes 86 oil producing wells and 24 gas injection wells. Eighty acre spacing was used to develop the 7840-acre unit. Devonian gas injection is based on a 320-acre nine spot pattern. The Devonian formation is a crystalline limestone, interspersed with chert. Average porosity is 15% and average permeability is 1 md. Gross thickness is 1000 ft. There are three reservoirs in the Devonian column: Upper, Middle, and Lower. The major reservoir is the Middle. The trapping mechanism is a northeast to southwest trending anticline with the south end cut by a normal fault. Flanks of the anticline are delineated by a water-oil contact.

Gas breakthrough can be a considerable problem in C02 flooding. From initially causing severe operational handling conditions to ultimately losing otherwise recoverable hydrocarbon reserves, industry personnel devote multiple resources, including time and money, to combat it. Maintaining injection below parting pressure is one effective method to minimize premature breakthrough in offset producing wells. Determining fracture gradient on an individual well basis in a periodic manner and adhering to the resultant rate and pressure parameters has aided the SACROC Unit's reservoir management. This paper describes the methodologies employed, data obtained and production benefits seen to date.

This paper discusses the information obtained from 22 mixed string sucker rod tests in sour crude (Arbuckle) production. The discussion includes field experience previous to the tests, reasons for conducting the tests, results of the tests and the benefits derived from the application of these data to field operations. The obvious advantage of mixed string sucker rod testing over other methods of sucker rod comparison is discussed.

This paper describes an Excel spreadsheet used to solve 3 challenging transient heat transfer problem for a well. A large number of unknown temperatures are solved numerically as a function of time on an R-Z grid. Time steps are controlled by a macro and the formulation is fully implicit for numerical stability. The situation modeled is hot oil injection into a well annulus in attempt to warm the tubing, thus melting wax and allowing its removal. Often the tubing is pumped while it is heating. Hot water or wax solvents are sometimes used in place of hot oil. The annulus may be (and often is) partly empty when annulus injection begins. The location of the injected fluid front is determined from annulus injection rate and other well data. When the injected fluid reaches the annulus sump level near the bottom of the well, that sump level rises rapidly because injection rate generally exceeds annulus drainage me. This rising sump level slows the possible downward advance of injected heat, which may not reach the needed depth. Examples reveal that the injected fluid cools with depth and that may affect job success.

The most important feature of an inhibitor protection program is how well the compound used matches the method of introduction into the system. This paper discusses those features of corrosion inhibitor compounds which are important for protection programs in producing oil and gas wells, in water floods, in gas-gathering lines, and in fire floods. In the process, the discussions will include the pros and cons of heavy inhibitors, of inhibitors for mixed-water systems and mixed air-hydrogen sulfide systems, and of vapor-phase inhibitors. Recent findings will be presented which illustrate the behavior of inhibitors when pumped into gas wells and which describe the use of a new organic inhibitor for aerated systems. Finally, monitoring methods for determining inhibitor effectiveness will be discussed.

As late as 1940, the method of pulling rods and tubing utilizing a horse-drawn single line over an A-frame mounted on wagon wheels, was in common use in shallow areas. For those who are not acquainted with this early operation we have provided an illustration to point out basically the simplicity of performance which has become a major part of our industry. One of the next steps in the progress of providing portable equipment to cover larger areas, was the Rumley tractor unit. This equipment served the Oklahoma, Eastland and the East Texas fields in the early stages. Following the Rumley tractor was the application of the servicing hoist to a relative fast moving truck which could take advantage of the highways to go from one area to another.

Vogel's inflow performance relationship relates the flowing well pressure to production rate for solution-gas drive reservoirs. Because two-phase flow exists, the graph of bottom-hole flowing pressures versus oil production rate results in a curved line. This trend accounts for the decrease in production as more gas comes out of the solution. Vogel assumes the initial reservoir pressure is the same as the bubble point pressure for the starting point of the IPR curve. This implies no gas has initially come out of the solution, i.e. the reservoir is at bubble point pressure. Saturated reservoirs, as studied in this paper, are initially under-saturated reservoirs with average reservoir pressure below the bubble point pressure. Traditionally, Vogel's inflow performance relationship has been applied to these reservoirs using the reservoir pressure as the starting point for the curve. However, due to the presence of gas at the reservoir pressure, this is not an accurate assumption. This paper modifies the Vogel IPR curve for use in wells within reservoirs that are below the bubble point pressure.

Over a number of years, the reference tool developed by Grant, White, Smith & Miller" and commonly referred to as "White's Injection Scale" has been widely accepted as a useful mechanism for planning and execution of cement squeeze processes in shallow and low pressure formations worldwide. In early 2001, refinements to the injection scale were developed that focused on applying many of the same concepts to two Permian Basin peculiarities: 1) The nearly exclusive usage of API Class C cement in squeeze operations shallower than 10,000 feet, and, 2) the high incidence of fracture gradients so excessively low that a full column of nearly any liquid is not supportable by the formation being squeezed. The modified injection scale is presented and explained. Incremental improvements provided by the modified scale are examined, and application case histories are described.

In rod pumping wells, the downhole data can be computed from the surface data by solving the one dimensional damped wave equation. Currently, the modified Everitt-Jennings method uses finite differences and an iteration on the damping factor to solve the one dimensional damped wave equation. The iteration on the damping factor allows for an automatic damping factor adjustment, which can be a valuable tool when dealing with large fields of wells. The damping factor pertaining to this method is a common damping factor for both the upstroke and downstroke. In this paper, a new iteration on the damping factor is presented, in which the algorithm is split such that the upstroke and the downstroke damping factors are refined separately. Results are presented.

Currently, API specs on 7/8" couplings allow for a wide variation in coupling face widths. The face width is critical when trying to achieve good rod makeup. For example, a larger face width is less likely to rotate due to the larger surface area i.e. more friction. As a result of the high number of rod pin-coupling failures, especially in the 718" section, a coupling with a more effective face width was developed.

Fiberglass sucker rods have proven to be an economical solution to many sucker rod beam pumping problems. Two important parameters that contribute to the effectiveness of FRP sucker rods are effective modulus of elasticity and fatigue life. Using established computer predictive techniques, it has been shown that FRP sucker rod installations can benefit from using rod designs with a lower modulus of elasticity. Fatigue life of sucker rods is an important consideration for any sucker rod pumped oil well, for both steel and fiberglass rods. Fatigue life predicitons for steel sucker rods can be routinely determined from API publications and recommendations. Fiberglass sucker rod fatigue life predictions are determined from guidelines supplied by FRP sucker rod manufacturers. The fatigue life of fiberglass sucker rods cannot be reliably predicted using methods developed for predicting steel sucker rod fatigue life due to the difference in fatigue behavior of the two materials. Therefore, test programs have been developed to generate reliable fatigue life guidelines for field applications.

With changing industry drivers, current petroleum industry needs and emphasis are on developing shorter, less costly, and environmentally-friendly well testing procedures. Several techniques have been presented to address this need. Although these vary in procedure and method of analysis, all rely on basic principles of fluid flow through porous media. In this paper, comprehensive evaluation of general closed-chamber tests, including general surge tests, and comparison with special tests such as impulse and slug tests will be provided. For each technique, the review will examine: - Hardware requirement, test design, testing procedure - Theoretical background - Method of data analysis. Similar techniques are compared using computer-simulated examples to determine expected degree of accuracy compared to conventional testing, with a significant portion devoted to field examples that show techniques to analyze the well-testing data from surge testing, closed-chamber DST, slug testing of oil wells, under balanced perforating and testing, and back-surge perforation cleaning.