The work described in this paper was performed in conjunction with a contract from the U.S, Bureau of Land Management, Pecos District to estimate oil and gas development in southeastern New Mexico for the next 20 years. This district covers the bulk of the Permian Basin in New Mexico, and contains numerous oil and gas reservoirs. Producing oil and gas fields of the region were divided into 27 plays, based upon similarities such as depositional environment, lithology, tectonic history, and trapping mechanisms. The approach relied heavily on
the work of Broadhead (2004) but expanded into reservoirs not covered in that study. Plays were analysed based on key factors such as geology, development histories, pool-wide production histories and trends, and the impacts of market demand, price, regulatory change, and impacts of changing technologies. Conventional resource potential of the Ellenburger play and unconventional resource potential of the Woodford Shale play are presented as samples of this work.

Secondary recovery projects continue to place greater demand on existing sucker rod pumping systems. Increased water injection, water breakthrough, and water encroachment have placed greater requirements on individual sucker rod pumping systems than was anticipated originally. This paper presents the conventional beam pumping production charts as a guide for reviewing the existing sucker rod pumping systems. The analysis will discuss gear reducer torque, rod stress, critical speed, and polished rod stroke length in conjunction with fluid production by pump diameter versus strokes per minute.

Core data can play a vital role in development drilling programs and recovery planning operations. Well-conceived field coring programs and subsequent laboratory testing procedures can strengthen log interpretation criteria, aid in completion/stimulation operations; provide a sound basis for reserves estimates and reservoir modeling, and supply much-needed guidance in secondary and tertiary recovery programs. This paper presents the need for pre-planning during the development phase of the reservoir so that necessary parameters are properly evaluated. Coring methods, coring fluids, preservation techniques, and basic laboratory testing procedures are discussed. Suggestions are given for selecting samples for special analysis test work.

To achieve maximum recovery from an oil field, especially when using supplemental recovery methods, the nature of the reservoir must be known in the greatest detail possible. In the past, several large reservoirs have been subjected to waterflooding under the assumption that they were "blanket" accumulations. When later detailed geologic analyses have been forced by a multitude of operational problems, the reservoirs were found to possess significant lateral discontinuity and/or marked permeability variations, requiring radical changes in the injection patterns. It is therefore important to reinforce the analysis of petrophysical and volumetric parameters of a reservoir with a sound geologic interpretation of the productive interval. This can best be accomplished by detailed examination of cores followed by careful correlation with well logs. Most of the following discussion will center on carbonate areas based partly on the author's experience in the Permian Basin, but also on the fact that carbonate reservoirs exhibit more complex porosity-permeability relationships than do sandstone reservoirs. Cores are slabbed simply by cutting a 3/4-inch thick vertical slice from top to bottom. The remnants are stored for possible special analyses based on interpretation of the slabs. The slabbed core is marked and placed in cardboard boxes which hold up to 18 feet (Fig. 1). The boxes can then be conveniently laid out on the floor or a long table for examination. The slabs are swabbed with mineral oil to bring out the natural features, leaving a strip along one side for observation of porosity and testing with acid.

A computational technique has been developed whereby formation evaluation of wells penetrating a long transition zone can be accomplished. This paper discusses how answers to pertinent questions relative to interstitial water and oil saturation quantity and distribution, water-oil level, optimum zones of completion, and zonal water-cut behavior can be obtained with a high degree of reliability.

The elements of a successfully planned and executed foam stimulation treatment have characteristically included surface and bottom-hole foam quality calculations, foam rheology, foam structure, surfactant and polymer requirements, pressure volume and temperature considerations, proppant transport, and fluid and nitrogen rates. Often taken for granted is the importance and advantages of foam flowback after the treatment to obtain maximum load recoveries with minimum or no proppant flowback into the wellbore or to the surface. A carefully planned and successfully used procedure is presented to allow more quantitative and precise control of foam flowback after a treatment is completed. Considerations for proper shut-in time, flowback technique, return fluid character, pressures, rates, closure stress criteria and formation damage will be made. The use of adjustable versus positive choke assemblies is discussed and advantages and procedures for the use of both are offered. Procedures for foam flowback from shallow, moderately deep and deep well treatments are recommended with considerations for bauxite and propping materials. Careful attention to the surface equipment preparation will result in obtaining maximum load recovery, with minimum proppant fill and/or flowback. This will allow the operator to realize the full benefits from the foam treatment sooner. Flowback procedures can significantly affect the resultant positioning of proppant in the packed fracture and subsequently the sustained productivity of the well. The importance of determining the closure stress requirement to enable adequate proppant entrapment in the fracture is presented. An equally important factor is the cooperation of the service company and operator in designing, and implementing these procedures. Understanding the consequences of not following these procedures is also important, and may offer clues as to why a foam stimulation job's results may not have been as good as anticipated. Key factors for determining that these procedures were not followed will be reviewed.

Due to out-of-zone injection problems in a water flood unit, investigations and a designed remediation to the problems was developed using diagnostics and new technologies with super absorbent crystallized co-polymer systems.Current profiles with their rates and pressure transients were analyzed through multi-rate injectivity profile analysis. Criterion were then established on the physical and chemical attributes needed by a solution to address the problems. The diagnostics while determining the problems and to what extent they were occurring, were also used to determine the placement control needed for a solution treatment. Once the needed physical - mechanical and chemical aspects were analyzed, selection of a solution also was restricted to utilize ones that would withstand the detrimental affects of CO2 injection and resistance to bacterial growth potentials. Shown are methods of diagnostics used, selection processes for needed attributes and solution capabilities, and the placement performance on the solutions. Treatment results show the process performance.

When a string of sucker rods fail conversely, the comment most frequently heard is that "they must have been rolled from a bad heat of steel;" this in face of the fact that sucker rod steel is rolled under far more restrictive requirements than ordinary structural steel. Following is a typical specification clause taken from an order, placed on a mill for sucker rod steel.

This paper describes a program to define the effects of free gas on the performance of electric submersible centrifugal pumps. The effects of the free gas show up as a deterioration of the head-capacity curve, such as areas of unstable head production, and effects similar to cavitation at higher flow rates. Depending on the amount of free gas through the pump, these effects may vary from slight interference to gas locking. Gas interference is indicated on the surface amp chart by rapid variation of the motor loading. Gas Locking occurs when the pump ingests too much gas and actually stops pumping because its head (or pressure) production is drastically decreased. This causes the motor to unload and to shut down because of low ampere surface control protection. When designing an electric submersible pump for a gassy application, it is desirable to know the amount of free gas the pump can tolerate and to compare this to downhole gas conditions. Thus, the objectives of this project were (1) to generate experimental data relating pump performance (i.e., head-capacity) to gas-Liquid ratio at the pump suction and to the pump suction pressure, (2) to correlate these data, and (3) to develop a model which would predict head-capacity performance of a submersible pump as a function of gas-liquid ratio, suction pressure, pump type, and any other pertinent parameter.

The useful life of oil field equipment is often measurably reduced by corrosion. There is a corresponding increase in both capital and operating costs which ultimately will shorten the economic life of the producing property. In the last 15 to 20 years there have been continuing advances in corrosion control technology. Such advances have resulted from a better understanding of the causes and occurrences of corrosion and steady improvements in mitigation materials and techniques. Successful corrosion control must begin with defining the problem and its cause, followed by the selection of a technically sound and economic means of mitigation. The latter can reach maximum effectiveness only when it is incorporated into a program which, after initial protection is established, provides for the routine maintenance of corrosion control measures, the required supervision and technical support and periodic evaluation. The purpose of this paper is to explore the types and causes of corrosion in oil field producing equipment, means for its control and how to obtain maximum effectiveness from corrosion control programs.

For the purposes of this paper, deep, hot gas wells will be considered to be those that fall within the following ranges of conditions: Deeper than 10,000 feet; hotter than 2000F bottomhole temperature (BHT); and bottomhole pressure (BHP) higher than 5,000 psi. Corrosive wells also contain an aggressive acid gas (H2S or C02) in amounts of 0.1% or greater. In addition, water production considerably aggravates corrosion especially if it is a heavy brine. When corrosion is observed, it is found to occur anywhere between the bottom and top of the hole, sometimes even continuously from bottom to top of the hole; rarely ever concentrated in just the top 2,000 or 3,000 feet which is normal for gas condensate wells. In general, the rate of corrosion is aggravated by increasing partial pressure of CO2 or of H2S. In some pure CO2 systems (H2S free), a passivation effect is observed when especially pure water and high pressure/temperature conditions are realized. However, even very small amounts of H2S (ppm's in the gas phase composition) can cause activation of the corrosion due to CO2 which affects the passivation effect. Corrosion rate is also aggravated by increases in temperature, in water production rate, and especially by the production of heavy brines. Heavy brine production indicates that a considerable volume of aqueous electrolyte is contained in the hole in contact with the CO2 or H2S and thereby causes considerable aggravation in both the area of steel which is corroding as well as the rate of corrosion.

Equipment handling water containing relatively large quantities of carbon dioxide and hydrogen sulfide is susceptible to excessive corrosion which may attain conditions not economically controllable using corrosion inhibitors. One such extreme condition developed in the Wickett Waterflood in Ward County, Texas where selective injection into multiple zones through common wellbores necessitated annular injection which eliminated the feasibility of using downhole protective coatings. Severe tubing corrosion was observed and continued even after inhibitor treatment had been increased to as much as 72 parts per million. This relatively expensive inhibitor program justified removing the corrosive constituents

Corrosion of drill pipe and protective casing strings is now recognized as a serious problem. In the past, very little attention was given to corrosion, due to the lack of understanding that most drill-pipe failures were due to corrosion. In areas where serious embrittlement failures occurred, treatments were designed to treat only the zones where hydrogen sulfide entered the drilling fluid. Through time, various types of treatments showed that corrosion could be controlled. It became evident that treating the entire depth of hole provided the most benefits. The recent shortage of drill pipe has accelerated attention toward saving pipe with a proper drillpipe corrosion program.

The primary objective of this paper is to stress the importance of a systematic organized corrosion control program. In order for us to see the great problem at hand and fully realize the importance of such control practices, we must have some understanding of the basic fundamentals of corrosion.

Corrosion has long been a problem in drilling and production operations. This paper discusses the basic causes of corrosion along with effects of different drilling fluids on corrosion rates. Current trends in drilling fluid systems and their effects on corrosion problems are discussed as well as technology presently available for detection and treatment of corrosion.

Corrosion in waterflood is a challenging and important problem. It is challenging because so little is known about it; important because the production of so many barrels of oil rests upon its solution.

This paper presents a resume of current practices in chemical inhibition of corrosion in the Permian Basin.

It is the purpose of this paper to scrutinize the more common field and laboratory methods of corrosion evaluation. It will be an unbiased evaluation exploiting the advantages and disadvantages of each system.

To simplify corrosion and corrosion inhibitors, one may sat that corrosion is an electrochemical process in which a given metal seeks its lowest stable free energy state and a corrosion inhibitor is a substance which possesses ability to insulate or otherwise prevent action of the electrochemical cells.

Corrosion inhibitors developed for low alloy metals have been found to have limited use on stainless steels such as 13Cr. Stainless steels are being successfully used to combat H2S and CO2 corrosion but are proving susceptible to hydrochloric acid (HCl). This paper presents results of tests made with 13Cr steel subjected to corrosion by HCl. Several inhibitors and inhibitor systems are compared under varying temperatures and acid concentrations. These comparisons reveal (1) 13Cr steel's greater susceptibility to corrosion than that of low alloy N-80 steel, and (2) the effects of different corrosion inhibitors in reducing the attack on the metal tested.

Successful corrosion control in producing oil wells depends upon two indispensable factors: 1. The inhibitor
must be capable of controlling the corrosion, and 2. The inhibitor must be applied on a rigid schedule
and in a manner which will insure that it comes into contact with all surfaces to be protected.

Corrosion monitoring is the foundation of a corrosion control program. The information derived is necessary to determine need, extent, and performance of corrosion control measures. This paper discusses corrosion monitoring in oil and gas production. Basic philosophy is presented. Many different types of monitoring methods are addressed. The advantages, disadvantages, and application of each are presented. Emphasis is placed on methods addressing corrosion by produced fluids. Only common field methods are discussed. Techniques for monitoring cathodic protection systems are not covered.

Knowledge of the various approaches to solving corrosion problems and familiarity with corrosion control techniques are important to the "profit improvement programs" of today's oil and gas producer. This paper presents a resume of internal corrosion problems and corrosion control methods in the producing industry. The basic causes of corrosion and basic methods of control are reviewed. The effects of the many oil patch environments on production equipment will be mentioned. The options for corrosion control will be discussed for several general problems including: down-hole corrosion in various types of producing wells, separation equipment and tankage corrosion, and water system (waterflood and disposal) corrosion. The paper attempts to help the reader "scope in" on his specific problems through an awareness of the over-all picture. A list of "Additional Reading" will be included for those who want to dig deeper into specific subjects. The verbal presentation will be illustrated by approximately 100 35mm slides.

Operators have used equipment and parts made of stainless steels in Permian Basin oilfield operations for years. The material is an improvement over carbon steels in corrosive water environments, but stainless steels are a poor choice when used in sour high chloride produced water service. Parts made from stainless steel in this service are subject to chlorides-induced corrosion. The problem can be even worse when the part is also subjected to fatigue loading.

Most corrosion problems in packer fluids occur from small concentrations of materials unintentionally added to the packer fluid or from foreign materials that contaminate the fluid during or after its placement. Bacterial growth, as well as oxygen saturation, can be responsible for corrosion in mus systems. Oxygen and sour gas contamination are the most common corrosive agents in brines, while oil gives the most trouble-free system from a corrosion standpoint. Consideration of a few corrosion fundamentals will permit the engineer to make the choice of a chemical treatment for a given packer fluid or choose a packer fluid which will give the most protection to casing and tubing. Special fluids and related dead space corrosion problems are briefly considered.