Many factors are involved in successful completion of a well. It is well accepted that the best cement hob possible is of prime importance. For a good cement job, the contamination of the cement by the drilling fluid should be minimized so that the cement can develop its desired properties. In addition, the drilling fluid should be thoroughly displaced from the annulus so that a competent sheath of cement can form a bond to both the pipe and the formation. When the drilling fluid is not thoroughly displaced, thus allowing commingling with the cementing composition, many undesirable results may occur. Laboratory work and field results show that spacer fluids can be advantageous in assisting in keeping the drilling fluid and cementing composition separated and also aid in more effectively removing the drilling fluid from the annulus. This paper identifies the properties that a good spacer should possess to function properly and discusses general practices in the use of spacers.

Permeability reduction in the critical zone (one to three feet) surrounding the well bore will seriously reduce production of liquid or gas. The permeability reduction can be caused by such things as mud and cement contamination, migration of formation particles, and deposition of material from water or oil. The removal of the damage and the restoration of the permeability in this critical zone requires the use of special acids and additives. It is first necessary to determine the cause of permeability reduction. With this knowledge, the proper materials and techniques can be applied to remove damage and restore permeability.

In 1982 Texaco USA initiated a study of producing field automation in the Midland Producing Division. As a result of the study, all facets of one producing field were automated. Based on acquired knowledge from this project, Texaco's Midland Producing Division and our Houston Information Technology Department (In>) initiated the construction of a sucker rod pump-off controller based on available off-the-shelf remote terminal unit (RTU) components. This paper will explain some of the choices associated with the POC application and discuss future RTU applications. The driving force behind Texaco's development of the Rod Pump Monitor Controller was the need for wellsite information at a central location. Market availability of off-theshelf pump-off controllers was limited, and the fundamental building blocks for a general RTU based system were readily available. This same general RTU can be used for injection control, automatic well testing, tank battery monitoring and control, and electric submersible pump control.

Reservoir stimulation procedures that perform well for pressure depletion reservoirs are often inadequate for the effective modeling of water of gas injection operations. Special capabilities are required to handle the upward and downward transition through a bubble point that varies depending upon injection material and stage of depletion. Also, the ability to track the front or fronts requires additional features to prevent serious error. Tests showing the importance of these phenomena are included.

In this day of specialism it is only natural the oil well pump manufacturers should follow this normal trend by supplying pumps which are designed for specific application. Heretofore, the oil producer has been obliged to utilize available pump assemblies in an effort to combat unfavorable well conditions. In doing so the volumetric efficiency of the pumping system has been considerably lessened. Our discussion concerns two such pumps which are designed for specific applications, the Double Volume and the Two-Stage.

The double displacement type pump is of relatively recent vintage. It was primarily designed to provide an economical method of producing oil under certain conditions. As "slim hole" completions became more and more common, it became obvious that production requirements could not always be met with an insert or tubing pump. This was especially true in areas where water encroachment had become a problem, or a water flood program had become a problem, or a water flood program had been initiated. These pumps are considered a specialty item and as such are somewhat more complicated than the single plunger type pump. Understanding the operation of this pump should encourage its use.

Traces development of requirements for special tubular products for wells. Describes manufacture, heat treatment, testing and inspection of tubular goods for use in critical well services requiring high strength materials or involving corrosion, corrosion cracking or embrittlement in the presence of hydrogen sulfide. Discusses yield strength and hardness limits. Proposes specifications for special tubular products.

The Spectralog is a tool that measures radioactive formations. In the past, all radioactive kicks on a conventional gamma ray have been considered shale. With this new tool, we are able to determine that these radioactive kicks are not all truly shale but formations that are oil or gas bearing in certain areas. We are able to find additional hydrocarbons that conventional logs have missed. This paper will show many examples in which this has happened.

This study uses actual production data to determine the optimum characteristics of fracture treatments in the Spraberry Trend of West Texas. The details of 116 fracture treatments along with corresponding production decline curves are utilized. The paper uses production data to characterize treatments on the basis of fluid volumes, proppant volumes, fluid type, and injection rate. After isolation of the best fluid We * the treatments are then compared on perforated height, limited entry effects, proppant type and proppant concentration. In an attempt to explain the results, fluid characteristics and fracture theories are discussed. In conclusion, a generalized treatment recommendation is prepared which utilizes the findings of this study.

The Wickett Field in the Permian Basin, located 40 miles West of Odessa in Ward County, Texas, is a mature field where squeeze operations occur approximately once per week on each workover rig. Historically, squeeze designs and success ratios have been evaluated individually on a "job by job" basis; this has maintained squeeze cementing costs at a very high level for both the operator and the service company. These costs can include factors such as initial and repeated cement laboratory testing on varying cement slurries, on-site pumping services, cementing additives, surface and down hole equipment, administrative and engineering time of both the operator and service company personnel, rig time, and repeated costs with each squeeze attempt. For some operators, additional factors can contribute to the complexity of this process such as limitations on a consistent methodology or organized approach to the operational aspects of a squeeze operation. Variations can exist within engineering, field supervisory, and service company personnel as to proper on-site pumping techniques, cement slurry design, or necessary volumes of cement for initial or subsequent attempts. Often times, a very limited established or organized method is in place for "looking back" on the success or failure of any particular cement slurry or operational technique. Finally, an overwhelming amount of selections are available in the design process concerning slurry design and operational techniques. We will show how an operator, in close association with a service company can establish specific guidelines to manage these complex variations. We will present the methodologies that have reduced the complexity and increased the manageability of an ongoing process. Through these efforts, laboratory testing, administrative and engineering time commitment by the operating and service company personnel, and overall costs in remedial squeeze cementing have been reduced. In addition, these methodologies have improved communications, helped standardized operational considerations, and have increased the probability of successful squeezes on the first attempt.

Production in the West Texas area is primarily from carbonate (dolomite and limestone) reservoirs. This environment presents a special set of conditions in the realm of squeeze cementing. Techniques have been modified in recognition of these features. As a result, a formerly poor squeeze record in the area has seen noticeable improvement. A major problem in this carbonate background is the existence of fracture network systems. These fractures occur naturally, are created inadvertently during drilling and completion, or result from well stimulation efforts. To compound the difficulties in remedial squeeze efforts, they are of probable vertical extension. This is supported by modern theories on hydraulic fracturing, and temperature and radioactive tracer work. Other common problems include abnormally low temperature gradients, low standing well fluid levels, and long intervals of perforations. In contrast to squeeze cement applications in permeable sandstones where prime interest is basically on slurry behavior within the perforations (or at least of nominal penetration), a major consideration in squeezing in a carbonate environment is the cement fill of fractures and/ or channels. There is less emphasis on filter cake buildup. This approach results in the use of larger volumes of slurries than normally used in squeezing of permeable sandstone reservoirs.

For over twenty years the industry has been concerned with problems of gelation and suspension of solids in packer fluids. In recent years considerable attention has been given to corrosion aspects. This paper discusses types of water-base packer fluids used in the past and difficulties encountered. It presents laboratory data comparing suspension agents for oil muds and cites field examples of oil muds used successfully to suspend weighting material and to protect against corrosion. Corrosion protection when using clear liquids as packer fluids is also discussed.

Stable foam meets the need for a light weight, non-polluting, space-saving fluid with the lifting characteristics of a 50 sec viscosity mud. The foam weighs 0.5 lb/gal and has a pressure gradient of 0.026 psi/ft while in circulation. Stable foam has been used successfully in workovers in West Texas, New Mexico, the Rocky Mountains and the West Coast in some 500 wells with high success ratios and a substantial reduction in cost. The application is best suited to deepening, coring, drilling or foamout of obstructions such as sand bridges, scale, cement and junk. A special application is that of liner removal and setting as well as liner cementing. The process adapts itself to a closed circulating system. The injected foam is nonpolluting, removing the hazard of leakage or spills in offshore work. The foam is used one time in circulation and then reduced with defoamers to a small quantity of liquid. These characteristics make it ideal for offshore workover fluid. Progress is being made in high-pressure foam structure for deep well work. Its application can be expected to increase as the industry becomes more familiar with the process.

Conventional three-stage separation is relatively simple. Mechanical low temperature separation can be expected to recover more condensate, but is inherently more complex and requires close supervision. This paper discusses economics and operating problems of these two methods of gas-condensate separation which have gained acceptance in West Texas.

When fracture stimulating a well, maximum wellhead pressure can be reached seconds after the high-pressure pumps are stopped following a rapid pressure increase during a "screenout" or other sudden flow stoppage. This maximum pressure is caused by a water-hammer effect. When this effect is ignored, maximum allowable wellhead and downhole pressures can be exceeded, even if pumping stops before reaching the maximum allowable pressure. This paper provides a method to calculate the water-hammer pressure. Data from several case study wells demonstrating the water hammer effect are compared to the calculated values obtained from the methods described in this paper. For tight formation screenouts, the predictions are within 12% of the maximum pressure recorded. Methods to help minimize the pressure surge are also presented. Use of these methods can minimize the risk to people, the environment, and equipment caused by the potential water-hammer pressure surge often overlooked in well treatment designs.

Acid and sand fracture stimulations are critical to economic production rates in many wells, particularly in the Permian Basin. Production rates from one well to its offsets often vary. The difference in rates may be due to the heterogeneity in the reservoir or due to the design or execution of the stimulation. Conoco and BJ Services jointly implemented a system to standardize testing and reporting procedures for Conoco's Midland Division. The goal of this system is to simplify post job evaluations. ensure that well tiles contain complete information and to continuously improve job quality. In addition the manual that was developed from this process will aid in training of new personnel and consolidate reference materials. This paper describes why the process was implemented, the types of information contained in the manual and how the process has improved stimulation design and execution.

Automation of artificial lift systems is essential for effective management of deliquification for gas wells. There are at least fifteen forms of artificial lift in use for gas well deliquification. Often more than one method must be used in a given field because some methods are preferable earlier in a well's life and others are better later in a well's life. Production Operators must have effective tools for gas well operation, surveillance, problem detection, control, and optimization. And, to be effective, there can"t be a different tool for each form of artificial lift; there must be commonality of approach. This paper reviews the current state-of-the-art in automation of gas wells, with a clear eye on the needs of the Production Operators for understandability, functionality, ease of use, and economics.

With the evolution of design and evaluation software for Electric Submersible Pump (ESP) systems over the last 25+ years, most of the development and emphasis has been on ESP design, or sizing. All of the ESP manufacturers have, at one time or another, been involved in internal development of ESP sizing software and there have also been several third party companies who have developed similar programs. This paper will introduce the expansion of a design and sizing software program into a tool, which can be utilized for time variable modeling and simulation. AutographPC@ Software version 4.0 is the latest in the third generation of ESP design software from Centrilift. With this release, the design capability has been expanded to include an ESP system simulator. This simulator adds the time variable to the sizing, in such a way that the user can see the dynamics of the well operation in conjunction with the ESP operating point.

This paper discusses two steam injection methods which are currently being used by the oil industry: steam drive and steam stimulation. Each method has inherent advantages and disadvantages. Variations and/or combinations of these methods have been used to utilize the advantages of both processes.

Failures in the sucker rod industry can be costly and time consuming. A thorough understanding of the critical factors affecting the overall reliability of steel is important to address these failures. Sucker rod manufacturing involves a lot of processes from different industries. The manufacturing and servicing of steel sucker rods involves a chain of processes starting with the steel mills, sucker rod manufacturer and eventually goes to the end user. There are a lot of critical factors involved in every step of the process before the product goes down hole. The goal of this paper is to prevent failures through awareness and education of critical factors affecting the overall reliability of
steel products used in oil production. The topics addressed in this paper are as follows: 1. Methods of steel rolling (traditional ingots vs. modern continuous casting). 2. Induction heating & upsetting and factors affecting the final quality of the steel. 3. Heat Treatment and factors affecting quality and reliability of steel. 4. Shot peening vs. shot blasting. 5. CNC machining. 6. Factors affecting overall reliability in the field.

Multiple zone WAG injection techniques have changed little over the years, relying on side-pocket mandrel / injection valve technology to accomplish injection fluid diversion to target zones. These systems rely on mechanical injection valves to disperse the injected fluid. A new technique has been put into use that both simplifies the process and provides increased reliability by eliminating mechanically operated injection valves. Side-pocket mandrel injection control assemblies have been replaced with new reservoir access mandrel systems. This paper will explore the application of this improved downhole technology for WAG injection control.

Carbonate formations are predominate in the Permian Basin and as such are commonly stimulated with acids. Success of an acid treatment is dependent on knowledge of the reservoir, design techniques and execution; and emphasis on obtaining good zone coverage. In addition, effectiveness is very dependent on how many times a well has been acidized and with what kind of acid. Case histories of acid stimulation, with production results, are presented on a new technique for stimulating the San Andres dolomite. Treatments were all low rate matrix treatments designed to minimize the increase in water production. Discussed are conditions to overcome in order to get effective acid penetration and thus stimulation. The case histories presented are on San Andres wells that have been acidized several times in the past, but where this new technique has provided an improved response over a longer period of time following the treatment.

Fracture acidizing of carbonates has yielded increases in production in many areas. But depending upon the rock strength and the reservoir closure pressure this may be lower than expected. Also, as a result of closure and rock strength, production may decline at a higher rate than after a proppant fracture treatment. Laboratory results are presented describing the effect on the strength (Softening) of a dolomite and limestone after exposure to various acid systems. A dolomite saturated with potassium chloride water exposed to neat, emulsified, gelled and crosslinked 15wt% hydrochloric exhibited strength improvements going from neat to one of the fluid loss controlled systems by approximately 70%. A limestone tested similarly showed approximately 100% strength improvement. Tests were also performed on the rocks in a dry state and saturated with synthetic oil. These tests also had marked improvements in from 25 to over 100%. Treatments using an increased volume of acid systems with lower matrix leak-off should provide longer-term production responses.

A great many carbonates are stimulated successfully utilizing acid fracturing techniques. There are several models in the industry, which will give relative comparisons of fluid performances under varying reservoir conditions. These are only good as design tools when validated. However, a great deal of laboratory time is spent testing rocks and fluids for reactivity, diffusivity and leak-off to provide the values for these models. It is on most occasions difficult to comprehend the significance of these results.Presented are the variances in laboratory generated values and their effect on the output of one of the fracture acidizing models. Several reasons are addressed as to why these variances occur. These include the difficulty in measuring accurately the surface area of samples tested, the limited amount of reservoir rock to test with all the same properties and the limited amount of time to perform the tests.

A stimulation treatment of water input wells in the massive San Andres limestone has shown the benefits that can be expected with the inclusion of nitrogen in the treatment followed by the use of nitrogen for displacement to the formation and the subsequent backflow. The San Andres is interspersed with water zones and the multiphase system helps prevent the fracturing of the formation due to gas compressibility and carefully controlled injection rates. The inclusion of a gas phase in stimulation treatments has been practiced for many years in production wells, but it has been only recently accepted in the treatment of water input wells in the Southwest. Wells treated cover the six-county area of Hockley, Terry, Cochran, Yoakum, Gaines and Scurry Counties. Two treatment techniques developed have shown that with a properly engineered treatment an increase of water input and effective cleanout of solids can be expected.