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Production from thirty-two horizontal Devonian wells in the Permian Basin was studied in detail to determine if the impact of various completion methods might be distinguished from an existing reservoir overprint. Flowing transient pressure analysis was utilized to determine effective permeabilities and contributing lateral lengths. Production and economic performance were normalized for permeability, productive zone height, and initial static reservoir pressure on each of the wells, so that examinations into various completion processes would be more meaningful.

Usage of fiberglass sucker rods have proven to be the most efficient means of producing artificial lift wells in the Pioneer Natural Resources, Spraberry Trend Area. Fiberglass/steel designs are being installed on all new drilled wells and will remain in place for the life of the well. In this paper examples will be given of production improvements when going from an all steel to a fiberglass/steel design, various designs which decrease string weight 13 to 26%, benefits of the lighter more elastic rod and comparison of failure data.

Curable resin-coated proppant (RCF") is used in hydraulic fracturing treatments primarily as a means of preventing or reducing proppant flowback during post-frac clean-up and production. The RCP is generally placed in the fracture with water based crosslinked fluids. In order to effectively remove these viscous fluids which are detrimental to fracture conductivity from the proppant pack, it is necessary for a reduction in the fluid's viscosity to occur. This reduction in viscosity, or breaking, may occur either (1) thermally (2) with the addition of enzyme breakers!

Curable resin-coated proppant (RCF") is used in hydraulic fracturing treatments primarily as a means of preventing or reducing proppant flowback during post-frac clean-up and production. The RCP is generally placed in the fracture with water based crosslinked fluids. In order to effectively remove these viscous fluids which are detrimental to fracture conductivity from the proppant pack, it is necessary for a reduction in the fluid's viscosity to occur. This reduction in viscosity, or breaking, may occur either (1) thermally (2) with the addition of enzyme breakers!

Increased demand for crude oil and the higher prices being paid for petroleum products have caused a resurgence of activity in the Spraberry Trend of West Texas, (Fig. 1). Even though it is one of the largest producing areas in the industry it has always been somewhat of an enigma to those working with it. However, with proper planning and execution of the completion phase, new wells in the Spraberry-Dean sections, and re-. completions in the Dean zone can be economically attractive. The Spraberry and Dean zones are primarily siltstones with very low matrix permeability and porosity.

Beam pumping systems are operated in challenging and hostile environments due to the ever increasing demand to produce oil in a fast and efficient manner. The goal of this project is to increase the efficiency of these beam pumping systems by studying and optimizing some of the critical factors affecting sucker rod

Beam pumping systems are operated in challenging and hostile environments due to the ever increasing demand to produce oil. Marketing research revealed the fact that 70% of failures in this industry were rod pin failures. An in-house research & development project/experiment was conducted to address some of the critical factors governing rod pin failures. The experiment uses core engineering concepts of stress, strain, torque and circumferential displacement and explicitly answers the following questions.

The Beam Pumping System, in onshore oil wells, is a major part of the artificial lift method. Utilizing the energy from the Pumping Unit, to operate, the BGC lowers the cost of compression and eliminates the emissions created by other compression systems. By utilizing the Pumping Unit as the BGC's prime mover, operators enjoy a steady increase in production with a "tried and true" compression system that is considered a GREEN MACHINE by the industry.

A discussion of the mechanics involved in gas lifting individual wells with a small rotary-compressor system. Technique, applications, and advantages are presented. Example installations and their costs are included.

In the geographical areas of North and West Texas, 94 percent of all oil wells produce by means of artificial lift, and most of the artificial lift installations consist of sucker rod pumping equipment. This percentage equates to some 100,000 rod pumping units in this area alone." With these facts in mind, there should be no doubt as to why the proper management and surveillance of pumping equipment are important. This paper is limited to a discussion of computer application in the management and surveillance of rod pumping equipment.

Forty years ago there was little problem with the analysis of a well log. The only type of log that was available was an Electrolog. This survey was used to determine the depth of the pay zone, the thickness of the bed, and the location of the oil-water contact. As time went on, more and more different types of logs were developed and the analysis of each was fairly simple and straightforward. However, a problem was developing in the interpretation of wells. What could be done on a well which was logged with two, or three, or four different tools?

The Shell-operated Denver Unit of the Wasson Field consists of approximately 850 producing wells. Over 700 of these are being produced by sucker-rod pump. Average production is about 400 BFPD with an average water cut of 60 percent. Surveillance of the rod-pumped wells is being achieved with a computer-based pump-off control. Initial benefits of 4 percent increase in production and an I8 percent savings in electrical energy are being achieved. Other operational benefits which are realized are described.

The use of simulation in petroleum engineering is not new; pipeline and refinery simulation and simulation of reservoir performance have been widely used in the past. However, in recent years there have been major improvements in the ability to simulate rod pumping situations, such as the use of mathematical expressions and equations (derived from API RP 1lL) to capture succinctly complex interrelationships which heretofore could not be easily related. The model is then manipulated on the computer to see what might happen in reality if the relationships were fixed or varied in specific ways.

Although it looks simple, rod pumping equipment requires complex simulation methods to mimic the variety of actual conditions encountered in the field. This paper describes such a method which relates the influence of unit geometry, prime mover slip, rod design and downhole pump condition. The method is mathematical, but non-technical means such as dynamometer cards and electrical terms are used to describe it. The intent of the paper is to study a variety of practical rod pumping questions that frequently arise.

Sun Exploration and Production Company (Sun) conducted an extensive five-year study into the costs and benefits of installing and operating a Supervisory Control and Data Acquisition (SCADA) system. Installed on the Southeast Levelland Unit (SELU), the SCADA system was operated as a full monitoring system. The SELU is a secondary recovery unit located in the Levelland Field in Hockley County, Texas. The five-year period included 30 months prior to the initial operation and 24 months following full operation of the system.

Computer programs have been perfected for the design of continuous flow and intermittent gas lift installations. Calculations can be performed for all standard designs, for macaroni and annular flow installations, and for wells where wireline retrievable valve-mandrels were previously installed. Using the same well data, the computer calculates installation designs which duplicate accurate hand calculations using the same graphical procedure. The resulting printout provides a complete permanent report of all information pertinent to the design.

Marathon's Ezzaouia #8 well is located in the Ezzaouia concession in the Zarzis permit area of Eastern Tunisia. The well is completed as an oil producer in a 7300" Jurassic sandstone and has never sustained steady production with the existing 3-l/2" tubing. Systems analysis suggest that the well could flow, at least temporarily, with smaller tubing or could sustain production for a much longer time with artificial lift. Installation of a rod pumping system would be an easy decision in most parts of the world, but due to a lack of workover rigs in Tunisia a rod pumping system was not selected.

The concept of continuous-rod pumping is nearly as old as the rod pumping system itself. However, there was a Three-fold problem with the concept. First of all, there was a problem of manufacturing the continuous-rod and finding a suitable means of heat-treating the rod. Secondly, after the rods had been welded together to the specified length for a given well, there was the question of transporting the rod string to the well. And finally, there was the difficulty of handling the continuous-rod in running and pulling the rod string in the well.

Once primary oil recovery from a reservoir has been accomplished, secondary and enhanced oil recovery techniques have been used to further the life of the field. Some of the most commonly occurring problems encountered with these techniques are: 1. Lack of confinement to the section of interest 2. Permeability variations in the producing zone 3. Early water breakthrough due to fingering of the injection fluid through
the oil 4. Directional permeability from injection wells to producers

Design and implementation strategies for maximizing the economic rate of return for conformance-improvement polymer-gel treatments will be reviewed. These design and implementation strategies are based on 20 years of field experience and based on number of large field projects involving a single polymer-gel technology. The presentation will be limited to discussing gel treatments that are applied to reservoirs suffering from fracture and/or other high-permeability (>2 Darcy) reservoir flow anomalies.

The Conroe Field contains 959 wells which produce primarily from the Cockfield and Main Conroe Sands. The Main Conroe Sand, encountered at about 5000 ft, yields an average oil production of 35,000 BPD. This field was discovered in 1932 and has a remaining life expectancy of more than 25 years. About 60 percent of the total wells are on gas lift. Gas production from the Cockfield zone plus oilwell residue gas from the Main Conroe Sand supply most of the gas lift gas. Two gasoline plants in the field gather the low pressure residue gas.

Oil may be lost from a tank in the gas or vapor phase form, a phenomenon which is known as evaporation loss. The evaporation loss to the atmosphere from lease tank batteries is a definite loss of our natural resources. The question, is this evaporation loss great enough to have any monetary value at the present time? Are there economical methods for recovering these vapor losses and are such methods profitable to oil producing operations?

Efficiency of primary and secondary oil recovery has become a major economic requirement for all crude oil producers. The phase of crude oil production this paper will consider is final gas-oil separation with the stock or surge tank and recovery of the resultant vapor. A basis for consideration of stock tank vapor recovery will require a gas sales outlet at a centralized location where crude oil is treated for pipeline sale or storage.

This paper demonstrates the design and application of vapor recovery systems, including treating systems for boosting recovered liquids into plant line, crude stabilization, well casing pressure control, battery systems, and casing vapor recovery systems.

Most so-called gas reservoirs which produce liquid in the ratio of ten barrels per million or more are actually retrograde condensate reservoirs. As retrograde condensate reservoirs, they exhibit a dew point and condense liquid in the formation upon reduction in reservoir pressure. This liquid condensation in the reservoir adversely affects the production of liquid and gas at the surface. In extreme cases this retrograde condensation in the reservoir may result in the loss of as much as 75 to 80 per cent of the stock tank condensate initially contained in the reservoir fluid.