This paper is a review of the operation and performance of the Goldsmith-Cummins (San Andres) Unit, The Unit is located in northwest Ector County, Texas. It produces from the San Andres dolomite at approximately 4200 ft. The general Goldsmith Field structure is an anticline with two large domes connected by a productive saddle. Gas caps are present in portions of the field. First field production began in 1934." The Unit is operated by Atlantic Richfield Company. It is composed of 191 wells; most wells were drilled and completed prior to 1940. The general completion procedure was to drill to 3900-4100 ft, set casing, deepen to total depth and treat acid and/or short with nitroglycerin. A few of the wells were fracture treated during the 1950's and 1960's to increase production rates.

Secondary Recovery was introduced to the oil field some years ago. One of the most advanced secondary recovery projects to date was "kicked off" by the Atlantic Refining Company on May 9, 1958, on the H.T. Boyd Lease in Slaughter Field, Texas. This project consists of injecting propane, then gas, then water into the San Andres pay. This paper will explain briefly the operation and problems encountered in this Miscible Slug Project.

Factors affecting the proper selection, installation and operation of deep shaft-driven centrifugal pumps. Use in source wells for secondary recovery projects is outlines, especially with reference to temperature and solids content of the supply water.

Hydraulic pumping units are classified as surface or sub-surface. Our discussion refers only to surface units which reciprocate a sucker rod string connected to a sub-surface plunger pump. Hydraulic unites may be classified as counterbalanced or non-counterbalanced. The counterbalance is provided by weights or compressed gas. Our discussion will be based on compressed gas- counterbalanced units and non-counterbalanced units.

The increasing cost of producing oil has caused operators to expend every effort to reduce operating expense. This expense is always increased when an artificial lift is required. The most popular type of artificial lift has been the beam pumping unit. The operation of this type of pumping unit may become very costly without proper care and maintenance of the equipment. Primarily, the responsibility for this operation falls on the field personnel of the oil company. Through training and experience, they have learned the techniques and procedures required for the pumping of individual wells. We would like to discuss the correct techniques and procedures necessary to assure satisfactory operation of this pumping unit.

The operation and maintenance of equipment on pumping wells has always been considered the function
of the field man in the oil business. Primarily this has been true because of the fact that the field man,
through his training and experience, has handled the equipment and learned the techniques and procedures
suitable for the pumping of individual wells under the varying conditions that are encountered. The operation, care, and maintenance of the surface equipment, particularly the pumping unit, is what we would like to discuss here.

Several operational changes have taken place at Block 31 to reduce operating costs and increase revenue. The most significant change has been the utilization of waste heat for treating oil emulsions. This has resulted in increased gas sales by reducing fuel gas requirements, a reduction in operating costs, and the elimination of a potential safety hazard. Computerized test equipment has been installed to provide more accurate testing, which in turn has provided improved data to assist in the management of the reservoir. A plunger gas lift system is being used to improve lift efficiency and to reduce operating costs.

Federal regulation of prices charged by producers of crude oil was based on a "property" concept focusing on the "right to produce" as it existed in 1972, which the Department of Energy (DOE) and its predecessor, the Federal Energy Administration (FEA) attempted to define and clarify through numerous Rulings, Interpretations and Decisions. Producers often faced substantial liabilities in the context of compliance actions by the Economic Regulatory Administration of the Department of Energy by reason of their failure to designate properties in accordance with Department of Energy Regulations and Rulings. By the same token, however, Producers often failed to take advantage of the substantial flexibility inherent in the DOE property definition. Unfortunately the ambiguities, interpretative problems, uncertainties and risks which have attended property determinations and designations under crude oil pricing regulations did not cease to exist on January 28, 1981, when President Reagan signed an Executive Order removing all federal price controls on crude oil. The Crude Oil Windfall Profit Tax Act of 1980 relies upon and incorporates by reference the Department of Energy regulations as they existed in June, 1979, for purposes of determining the appropriate taxation tier for crude oil-- "without regard to decontrol of oil prices or any other termination of the application of such regulations. The term "property" which was the pivotal concept in determining whether crude oil qualified as "new oil," production from a "stripper property" or "newly discovered crude oil" under the June, 1979, regulations has been defined in Section 150.4996-I of the excise tax regulations under the windfall profit tax as having "the same meaning as that term is given by the energy regulations. Just as a failure to understand and properly apply the property definition under price regulations resulted in substantial over or undercharges by producers, such failure could result in taxation at an improper tier under the Crude Oil Windfall Profit Tax Act of 1980, resulting in some instances, in taxation of crude oil production at substantially higher rates under one tier than would apply under another tier for which the production could also properly qualify. The following discussion is intended only to point out the factors involved in a property analysis and is not intended to serve as a complete guide to property determinations.

Water soluble polymers find three major applications in oilfield enhanced oil recovery projects. Two of these applications involve reservoir fluid mobility control while the third involves profile control via reservoir heterogeneity modification. All polymer applications in the oilfield require certain operational practices to ensure that the polymers can function as designed. Many of the design criteria involved in polymer applications include production and injection equipment modifications in conjunction with reservoir fluid chemistry considerations. Finally, the proper choice of specialty chemicals to support injection and production of oilfield polymers is essential to the ultimate success of the projects. Two types of polymers are used in oilfield applications, the hydrolyzed polyacrylamides and the xanthan polysaccharides. Although each have their own specific advantages and disadvantages, the injection water quality requirements are essentially identical for both polymer types. A combination of specialty chemicals and specialized equipment is often required to meet the strict water quality requirements. In any system compatibility of all components is essential. This paper will discuss the water quality requirements and the problems involved in designing a compatible system. On the production side of polymer applications, compatibility is again of paramount importance. Saleable oil can only be attained if emulsions that are stabilized by the interactions of polymer, surfactants, solids, water, oil and bacteria can be resolved. Obtaining disposable or reusable water while minimizing produced fluid corrosivity is also a major consideration. Once again, systems must be designed that can effectively employ specialty chemicals (e.g. demulsifiers, water clarifiers, corrosion inhibitors, scale inhibitors, biocides), and mechanical techniques that minimize operational problems.

This paper points out some of the operational difficulties that may arise in water flooding and shows major factors which must be considered to arrive at a solution to the problems.

This paper is presented to clarify a few of the general problems encountered in water flood operations. The production personnel are responsible for the production of the water supply wells, operation of a water plant and distribution system, and supervision of water injection wells. These duties are in addition to their usual occupation

The recent growth in applications of a new carbonate stimulation technique, which involves the construction of numerous tunnels or short laterals out of a main wellbore by using coiled tubing, has yielded excellent production improvements. A simplified mathematical model to analyze this acid stimulation process is presented in this paper. From the perspective of reservoir properties, this simulation takes into account the reservoir heterogeneity, drainage size, permeability, fluid characteristics, porosity and skin factor. From a tunnel construction perspective, the simulation considers the influence of acid jetting angle, tunnel geometry, tunnel numbers, and eccentricity in different pay zones on well productivity. Meanwhile, from an acidizing viewpoint, the simulation considers effects of acid concentration for tunnel initiation and extension, rock solubility, and acid spending. These capabilities guide job design and reservoir performance analysis in field operations. As an example, a comparative study of different tunnel configurations for optimizing production is provided.

A case study has been conducted on Red Fork formation wells with bottomhole temperatures ranging from 225 degrees -250 degrees Fahrenheit. The fracturing applications and techniques in this area had historically provided lower than expected post-treatment productivity and a rapid decline rate, .suggesting that the fracture conductivity were less than optimum. Joint efforts of the operator and service company, utilizing state-of-the-art fluids, breakers, and design methodologies, were employed to optimize well productivity. The case histories of hydraulic fracturing treatments and subsequent production performance of five offset wells are analyzed and presented. Average incremental production rates were significantly improved through application of the new technologies, clearly demonstrating the effectiveness of the modifications.

Many of the benefits of the Ultra-High-Slip motor can be realized by its installation under the exact same conditions as that of the Nema D motor. However, to maximize the system efficiency and minimize operating cost, some changes may be required to optimize the Ultra-High-Slip system. The amount of effort required to optimize your installation will depend upon the particular well. In this paper, we will be discussing three well tests. All of them were conducted in 1985, Andrews County, Texas, for two different operators and on three different wells.

A field demonstration of the application of the bottom hole pressure data, as received from Real Time Diagnostics" wireless pressure transmission system, improved the efficiency of PanCanadian Petroleum Limited's 8A-19-38-Ol-W4m well in the North Bodo field of northeast Alberta, Canada. An illustration of servicing a typical North Bodo slant well on a pad of wells is shown in Figure 1. The Telemetry Acquisition Tool (TAS device, developed by Real Time Diagnostics (RTD), was installed in the production tubing below the producing zone perforations, where it was able to measure and accurately transmit bottom hole production pressures and temperatures of the well's producing horizon to the surface. The real time pressure data was relayed into a voltage loop and a surface computer which contained software designed to output an analog process signal. This signal was then sent to the Wermac Electric Limited's Variable Frequency Drive (VFD), which controls the speed and torque of the electric motor powering the bottom hole progressive cavity pump (PCP) system. PanCanadian was able to both increase the oil production and decrease the lifting costs per barrel by utilizing the actual bottom hole pressure response of the reservoir fluids flowing into the wellbore to optimize the daily rate of production.

The objective of this project is to use data mining to analyze well completion data to determine if trends or interesting patterns exist between well completion and stimulation methods and subsequent production. While a multitude of completion and stimulation techniques exist there are few objective, systematic examinations of their relative utility. A 370 well subset of basin Dakota wells drilled during 1994-2004 was examined to determine the feasibility of this concept with 58 additional wells drilled during 2004-2006 used for testing. Comparison of companies showed statistically significant differences in average production which could not be explained resolved by studies of land position via K-means clustering. Data mining was able to determine variances in first years gas production based on fracture fluid gallons, fracture fluid type, fracture interval thickness and sand lbs. A forward model was generated that could accurately estimate first years gas production based on these input parameters

This paper chronicles efforts to extend batch treatments using hydrocarbon-solvent solutions of corrosion inhibitor. Inhibitors were developed in the laboratory using parameters felt to be important for this endeavor. That is, good high inhibitor concentration inhibition, good reduced-inhibitor inhibition, and intermediate brine dispersibility. Field- testing proved these inhibitors to be effective during the extended intervals.

This paper describes a downhole separation technique that diverts the formation fluids into the basing annulus near the top of the downhole separator so that the liquids and gas can separate by gravity. A seating nipple is positioned at the bottom of the separator that is within inches of the liquids that exist in the casing annulus surrounding the gas separator to obtain unobstructed liquid flow into the pump inlet and result in higher pump fillage.
The separator design is used with a conventional packer, or a special pack-off assembly consisting of elastomer rings on a tube positioned between the separator and the tubing anchor below the separator, or a packer with tail pipe when the pump is set a considerable distance above the formation.
Two conditions affect pump fillage that can severely reduce pump displacement. A recent complicating factor that must be considered when evaluating gas separator performance is the recent use of high clearance plungers in the pumps. Large plunger clearances for sand problems are common in some areas that result in a pump plunger leakage of 50% the pump capacity, so the pump appears to be full or almost full when actually the liquid in the pump is circulated liquid that is bypassing the plunger and not new liquid being drawn into the pump chamber. The second condition is the lack of separation of free gas from liquid as the formation liquid enters the pump inlet.
The paper describes gas separation techniques and presents field data on several types of downhole gas separators.

A method is presented for optimizing roller cone bit hydraulics programs to provide minimum cost per foot drilled. The method differs from traditional optimization techniques in that optimum pump operating conditions are determined rather than being arbitrarily imposed as a constraint on the optimization process. The method considers rate of penetration (ROP) response to increased bit hydraulic horsepower (BHHP) as well as increased fuel and pump maintenance costs to provide increased BHHP. Optimum conditions may be determined through a parametric analysis or by imposing simple relationships between pump fuel and maintenance costs and ROP response to increased BHHP. Full scale laboratory drilling data under various overbalance pressure conditions are presented to demonstrate the relationship between ROP and BHHP. Laboratory and field results with blanked nozzles and asymmetric three nozzle configurations are also presented.

The Glorieta, Upper Paddock, and Lower Paddock formations were unitized in the Vacuum Field (S.E. New Mexico) by Texaco in 1992 creating the Vacuum Glorieta West Unit. A technical committee made up of working interest owners was formed to determine operational matters for the newly formed unit. The technical committee determined that the Upper and Lower Paddock intervals contained the more prolific productive capacity and provided the most suitable median for waterflooding. Consequently, unit wide water injection in those intervals commenced late that same year. Almost immediately water breakthrough occurred in the northern area of the field and in selective areas of the southern portion of the field. Unit production showed an immediate increase in unit water production accompanied by an actual decrease in unit oil production at the commencement of the waterflood. From this point forward the water/oil ratio (WOR) became the major driver of economic limit for the VGWU. It was not until the first quarter of 1994 that the Vacuum Glorieta Unit saw its first positive response to injected water, considerably after the anticipated time frame.

Tracing the fall of the plunger down the tubing can be used to optimize the operation of plunger lifted wells. On plunger lifted wells an acoustic liquid level instrument can be used to collect a series of liquid level shots down the tubing. These measurements are used to monitor the position of the plunger, as the plunger falls down the tubing during the time period the controller has closed the surface valves and the well is shut-in. The collected data is used to determine the 1) fall velocity of the plunger and 2) time for the plunger to fall to liquid. By accurately measuring the plunger fall velocity with an acoustic liquid level instrument, then the minimum shut-in time for the plunger lift installation can be determined. The plunger trace measurements will ensure that the plunger has reached the liquid at the bottom of the tubing by the end of the shut-in period. Setting the well's controller to have the shortest possible shut-in time period can maximize oil and gas production from plunger lift installations.

Many factors are involved when selecting the most cost effective artificial lift system. This paper will discuss the advantages of The DynaPump Intelligent Long Stroke Hydraulic Pumping System compared to other artificial lift systems. This system has characteristics that allow for operation at much slower strokes per minute greatly reducing tubing and sucker rod wear while retaining the ability to produce at greater volumes from deeper depths than conventional beam pumping units. This system also has features that provide superior efficiency and flexibility at any rate and depth compared to other artificial lift methods. This study compares electrical efficiency, well intervention costs, production optimization, adaptability to changing well conditions, ability to operate in harsh well conditions, and overall environmental impact between various artificial lift methods. Included are actual operating parameters and runtime comparisons. The conclusions will aid in the selection of present and future artificial lift system requirements.

BP Permian's Sprabeny production consists of 400 rod pumped wells located primarily in Midland, Martin, and Glasscock Counties. Of these, the Spraberry Core Production Area located in Glasscock County includes 80 wells, which have been producing for 30+ years. Development of the Wildfire Production Area in Midland and Martin Counties began in 1996. Wells in both areas are typically completed to about 9500" through the Sprabeny, Dean, and Wolfcamp formations. Pump depths fluctuate from 7600" to 9700" through the field. A variety of operating challenges have been encountered and worked through over the years to optimize profitability. The purpose of this paper is to discuss the teamwork and technology utilized in resolving these challenges.

Paraffin wax treatment in the Spraberry has been around since development began in the 50"s. Hot oiling and hot water have been the method of choice for many years. Chemical treatment and a combination of chemical with hot oil or water have also been alternate methods. The purpose of this paper is not to determine the best method or methods, but to attempt to define and extend the frequency of the treatment necessary to control the paraffin wax. Current treating schedules are 30, 45, 60 and 90 day. Ten wells from the Spraberry were selected for this project for monitoring via a SCADA system to establish an optimized scheduling program.

Proper design of high-volume pumping systems is essential in waterflood operations. An analysis of all the problems hampering efficient sucker rod pumping systems is necessary to arrive at the best design. Techniques of sucker rod selection, unit selection utilizing dynamometer analysis, permissible load diagrams, etc., will be discussed with a correlation of all components composing the complete high-volume sucker rod system