Having reliable and readily accessible relative permeability information is a problem for many reservoir engineers, particularly for waterflooding and other reservoir simulation calculations; currently, no central repository exists and data within a company is often not centrally organized. A large effort was required to collect data from public and private sources and modify it to fit a common format. The central database thus constructed maintains relative permeability data in a format that is easily retrieved and processed. Categorizing and modifying the original data for applicability to similar systems is considered, allowing for variations in connate water, residual oil, and critical gas saturations. The database must be easy to use and employ both tabular and graphical results. The software is menu-driven and selects data from central relative permeability files. Information such as fluid type, wettability, lithology, geographical location, and method of measurement is used to search applicable results. The program operates under W9X or NT 4.0 systems. The database may be downloaded at no charge from a University of Missouri-Rolla web page.

Fracturing has become a viable and important option for completing horizontal wells. This is especially true in case of tight gas formations. There are many fracturing processes and methods to consider for placement of these fractures. The optimization of the completion process including the number and size of fractures is still a challenging consideration. Fracturing of a horizontal well has unique aspects that require very special attention to obtain successful treatment. Differences between horizontal and vertical wells exist in areas of rock mechanics, reservoir engineering, and operational aspects. All of these aspects affect the optimization process for successful treatment placement and optimum asset performance. In this paper we will first discuss the various factors crucial to successful completion of a fractured horizontal well. We will discuss these factors in relation to both longitudinal and transverse fracture applications. Success factors will include the optimum perforation process, overcoming fluid flow convergence towards the wellbore in case of a transverse fracture, and the fluid flow and stress interference between multiple fractures. The paper will present field cases, laboratory, and numerical experimentations illustrating the impact of the various factors on the completion of the horizontal wells and the optimization of the fracturing process. The paper will also point to unique aspects that may be encountered during fracturing a horizontal well in tight gas formations.

This paper demonstrates lessons learned on a 5-year effort to improve and enhance field-wide influences on the Central Mallett and Slaughter CO2 WAG Units. The developments on data analysis, reservoir and production engineering, and solutions in these mature units have provided the opportunity to make major impacts on recovery and production rates, operation enhancements, and cost reductions. Focus on the total reservoir and development of a framework of data included information of the reservoir, completion design, drilling and workover history, production and well-test history, logs and diagnostic analysis, and placement options. An optimum conformance solution design for each injection well and the associated offset producers was the team's vision. This ongoing work's performance and evaluation for defining successes was through a review of the operator's economic drivers for sweep improvement, reduction of CO2, and water cycling-breakthroughs.

In straight or continuous gas lift, the flow is continuous, that is, not interrupted by intermitting nor aided by any artificial pumping method for obtaining submergence. This type of gas lift resembles a flowing well more than does any other type of artificial method in producing a well. Gas is injected at the top of the well through the tubing or casing, as the case may be, and the flow of the oil and gas takes place through the other pipe rather than the pipe through which the gas is admitted.

Commonly known as sour gas, hydrogen sulfide (H2S) is a highly toxic chemical agent found in petroleum drilling, production and refining operations. As secondary and tertiary recovery efforts are undertaken on older reservoirs, H2S is being found where previously it was not recorded. The gas is present in many crudes and is produced in common refinery processes such as cracking and desulfurization. Hydrogen sulfide is formed primarily by decomposition of organic matter containing sulfur. The gas occurs naturally in many geologic formations throughout the United States and is both toxic and corrosive. This colorless gas has the characteristic odor of rotten eggs and can be readily detected by the human nose. One can usually smell concentrations of less than 10 parts per million (ppm), with concentrations of 700 to 1000 ppm being fatal, even if exposure is brief. It is important to realize that continuous exposure to low concentrations of H2S (approximately 50 ppm) deaden the olfactory nerves, causing the sense of smell to become an ineffective detection tool. A variety of both federal and state regulations apply to the petroleum industry in areas known or suspected to contain sour gas. Federal regulations basically are designed to protect the employee and are handled through such agencies as the Occupational Safety and Health Administration (OSHA), the National Institute of Occupational Safety and Health (NIOSH), and the U.S. Geological Survey (USGS). Most state regulations are designed to protect the general public and require certain precautions be followed to minimize the chance of accidental public exposure to H2S. Probably the best known state regulation is Texas Railroad Commission Rule 36, whose degree of operator compliance depends on the radius of exposure based on the calculated concentration of H2S and the rate at which it is expected to flow from a well. Due to the occurrence and toxicity of hydrogen sulfide and the array of regulations concerning sour gas areas, a method of monitoring H2S becomes essential. Factors to consider in selecting a monitoring system include reliability and accuracy, ease of operation and maintenance, response time and expected lifespan of the system components. Another important concern of any H2S detector is proper placement of the sensor units, with special care taken to ensure all installation and location guidelines are clearly understood.

Most gas wells produce liquids that are often not removed from the well because of low gas velocity. Failure to produce these liquids severely restricts gas production. This paper discusses the continuous removal of these fluids from gas wells by gas lift. It will also discuss compressor installation and operation.

The objective of this presentation is to outline an approach to complete systems automation of a major oil and gas production facility with emphasis on telemetry and the fundamentals of digital coding as they apply to telemetry.

Recent changes in the federal and state clean air laws and regulations will affect the operation of glycol dehydration units used by the oil and gas industry to remove water vapor from natural gas. These laws and regulations will limit the amount of aromatic hydrocarbons such as benzene, toluene, ethyl benzene, and xylene (BTEX) and volatile organic compounds (VOC's) that may be emitted into the air from the glycol regenerator still vent. This paper will present an overview of the new laws and regulations as well as process control systems that may be used to control and reduce the BTEX and VOC emissions from dehydrations units. Flares, incineration units, aerial coolers, recycle units, and the efficient R-BTEX process will be covered.

To control lifting costs, we first must understand what they are. What parts are subject to our control. How much difference doe it make to our company if we can reduce the costs that we do control.

The theory of corrosion and inhibition is discussed. The types of chemicals used as inhibitors and generalized treating methods are outlined. Results of inhibitor treatment of various crude oil producing systems are given. A discussion of requirements for field testing and economics relating to the use of inhibitors is included.

When paraffin is deposited from crude oil on downhole and surface equipment, it can reduce oil production and increase maintenance costs. Paraffin may deposit in tubular goods as a hard coating that gradually decreases flow capacity of lines and producing capability of wells. Paraffin crystallized from solution may be trapped at restrictions (beans, valves, controllers) and cause complete or temporary plugging of the system. Pressure surges caused by intermittent plugging and extrusion of the paraffin can overload pumps, flood the separators, and may result in equipment failure. Mechanical and thermal methods have been most widely used to remove wax deposits. Although chemical inhibition has often seemed to offer promise of preventing wax deposition and reducing operating costs, field trials of commercial products by our operations people were generally unsuccessful. The purpose of this paper is to report on the development and field testing of a new wax inhibitor which has been used successfully and economically in hundreds of wells.

As deeper and deeper well are put on the pump, sucker rod strings are being subjected to higher and higher loads. As a consequence, joint failures are becoming more prevalent. This phenomenon is invariably due to corrosion fatigue. An understanding of the stresses and environment under which this occurs will suggest the means of control. Proper tightening procedures, corrosion inhibition, thread form and correct heat treating procedures are discussed.

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.