There are many ways that sucker-rod systems can be improved. Performance and utilization of available equipment can be increased without the installation of larger units at greater costs. The use of rod guides is an inexpensive method for optimizing machinery already on the lease. This method keeps capital expenditures to a minimum and also reduces pulling costs up to 50 percent. Rod guides were originally designed to combat crooked-hole wear, but operators have been quick to find other money-saving uses for them.

This presentation is directed toward providing application guidelines for hydraulic pumping systems, in an effort to improve the performance of the system which in turn should make the system more acceptable to the operator. In the last 20 years the manufactures of down well hydraulic pumps have invested a great deal of time and money in research and development programs to improve both reciprocating and jet type products that they offer to the industry. However, the success or failure of the system depends largely on the equipment being properly applied as is the case with the application of any method of artificial lift. The presentation will deal with (1) When hydraulic systems can or should be considered. (2) What types of production units and surface equipment are available. (3) Where can the different production units be best applied. (4) How can the system be installed to maximize its performance. A summary of the information provided puts forth the contention that given equal consideration with other systems and being properly applied, hydraulic pumping systems is a viable selection for artificial lift equipment.

The North Concho Bluff Field produces from the upper Guadalupian tidal-flat sandstone play of the Queen Formation. Recently, the waterflood production from the field had decreased to a point where it was barely generating a positive cash flow. A reservoir simulation model was constructed in an attempt to improve earnings by identifying areas of potential oil bypassed during waterflooding. However, the spatial coverage of modem well log and core data within the field was inadequate in describing the reservoir for the simulator study. A better method of describing the reservoir heterogeneity was needed. A 3-D seismic volume, having a uniform density distribution of data, was interpreted across the field. The reservoir interval consisting of four elastic cycles, encased by evaporites produces a classic trough-over-peak seismic response. Seismic attribute mapping of a portion of the seismic volume was used to better define the reservoir characteristics within the inter-well region. Final seismic-guided average porosity and average permeability grid files were used as inputs into a single layer reservoir model. History matching using these grids was accomplished with only minor adjustments to the model, as compared to using well data alone. The model identified an additional potential recoverable reserve target in excess of 2 MMBO. A limited drilling program was initiated to verify the model, resulting in better than predicted production. Using seismic-guided reservoir properties improved the reservoir description for the simulator, allowing for a strategic drilling plan to be developed. The method presented advances the application of seismic-guided reservoir properties from reservoir description to operational reservoir management. Through strategic drilling, the North Conch0 Bluff Field had gone from a stage of potential divestiture to adding significant cash flow from a

This paper presents an improved sucker rod pumping design method similar to the API RP 11L but provides more accurate answers. The design is based on developing look-up tables or graphs for the desired unit geometry and pumping conditions by using a wave equation program. The wave equation and simulation techniques are used to mimic pumping conditions and calculate the loads and displacements. Such an approach makes it possible to compare, on a general basis, the different pumping geometries.

A solution now exists for problems attributable to gas interference in down-hole rod-pump assemblies. With the patented Solution Valve (SV), designed and manufactured by Eagle Advanced Oil Field Technologies, gas entering the pump chamber as either free gas or initially as dissolved gas, can be effectively displaced. Positioned on bottom of the conventional plunger, the SV performs in conjunction with conventional standing and travel valves such that the pump chamber is charged with fresh well bore fluids during each pump cycle. Gas locking cannot occur, because all fluids entering the pump are displaced on each stroke, thus eliminating the buildup of residual, high-pressure gas bubbles below the plunger or between the SV and an upper travel valve positioned atop the plunger. Improvement in fluid displacement efficiency, with resultant lowering of fluid levels in the tubing-casing annulus, can increase the production of oil and gas. With the SV it is not necessary for the pump to tag bottom in an attempt to mechanically jar balls off seats and thereby stimulate pump performance. Redistribution of fluids within the SV can often eliminate fluid-pounding topic. Consequently, rod-parts, rod-cut tubing, failures of valve-rods and valve-rod guides can often be eliminated. Unlike conventional pumps, down-hole debris such as particulate sand, silt, iron sulfide, etc., cannot prevent closing of the SV. Uninterrupted fluid flow through the pump, in conjunction with a constantly rotating seal surface between ball and seat, prevent the accumulation of stagnant fluids and associated settling of debris above and beneath the plunger. Another ideal application of the SV is in wells where gas cannot be vented up the tubing-casing annulus and where it becomes necessary to pump below a packer. By being able to pump gas as well as liquid, and thus invulnerable to gas locking, the SV functions quite satisfactorily. The permanently centered and stationary bail and movable seat of the SV are also well suited for applications in deviated and horizontal well bores where non-vertical orientations can delay ball seating. Similarly, for installations where heavy, viscous crude oils are pumped, the positive and instantaneous opening and closing of the SV eliminate inefficiencies due to ball floating.

Field results of limited entry treatment through pin point perforating and controlled injection rate in 201 wells are presented. A comparison with conventional treatments is made.

It is becoming more important, due to greater depths, higher temperatures, and increased volumes, that the most dependable and economical pumping equipment be installed to produce oil wells at this time. It is important that the operator be fully aware of the advantages of the electrical submergible pumping equipment and make efficient use of it. This paper will bring out these more important advantages. When these advantages and operating techniques are understood and utilized by the operator, one of the most economical methods of well production can be achieved. The use of the gas separator to increase the efficiency of the pump and to eliminate the problem of gas-locking will be discussed. The various ways centrifugal, submergible pumping equipment can be used to produce oil wells and in waterflood operations will be covered.

Polyacrylamides hydrated in hydrochloric acid and crosslinked with iron-based ions have been utilized for a number of years as in-situ divertors in the stimulation of extended-length carbonate zones. A significant improvement to this process has been developed, field-tested, and placed into general use. Crosslinking the polyacrylamide with a zirconium-based metallic ion has proven to be an alternative with a number of advantages over existing systems. Dependency of the system on iron derivatives for crosslinking is eliminated, the precipitation of ferric or ferrous compounds that can cause sludging or stabilize oil/water emulsions is minimized, and viscosity degradation of the in-situ crosslinked acid is not completely dependent upon the rising pH of the acid as it spends. An external breaker is added to the system as an aid in apparent viscosity reduction. Case histories are briefly reviewed. Treatment design data, including fluid friction pressure curves and rheologies are presented for use by the practicing engineer. Input parameters suitable for the most common 3-dimensional fracturing and matrix stimulation modeling simulators are included.

It has been documented in field test results that in many cases a production increase can be obtained by replacing a steel sucker rod string with a fiber-glass and steel sucker rod string. (2) While these tests have demonstrated the value of fiberglass sucker rods, the beam pumping systems were still fairly inefficient because the pumping units that were being used were originally designed for use with steel sucker rods. A more efficient beam pumping system has been developed that uses fiberlass sucker rods in conjunction with a pumping unit that was designed to take greater advantage of the properties of fiberglass sucker rods. (3) This paper discusses the unique characteristics and history of fiberglass sucker rods, and examines how this new pumping unit takes advantage of the properties of fiberglass sucker rods to produce a more efficient beam pumping system.

A high quality cement bond between casing and wellbore is an environmental and economic imperative for the duration of a well. A strong cement bond provides zonal isolation and prevents gas migration, gas entrapment and excessive water production. The growing public concern about possible gas migration to fresh water or to the atmosphere has further highlighted the importance of achieving the best possible cement bond. A chemical preflush prior to primary cementing is an inexpensive and effective method to help ensure a quality primary cement job. Ideally, the chemical preflush should be multi-functional and not only remove drilling fluid residue but also provide other features such as: improve fluid loss control, improve water wetting of surfaces prior to cementing, and prevent or aid in the prevention of cement fallback. To achieve all these features, it is common practice to run a sequence or blend of chemicals to adequately prepare the wellbore for cementing. This paper discusses a single-component product built on sodium silicate that can provide all of the aforementioned benefits. Specific focus is directed towards the interactions between surfactants and sodium silicate in a flush

Separating water produced in conjunction with crude oil has been an ever increasing problem since Drake's first well. As refinery capabilities grew more complex and pipeline companies became more aware of the problems associated with water, their demands to lower the water content of oil expanded to those we know today. The process equipment arm of the petroleum industry has always reacted to these needs with ever growing efficiency. This paper reviews past efforts and introduces one of the latest advancements in crude oil dewatering, documents its state-of-the-art applied technology, and reports its resultant efficencies.

The industry has developed methods to improve the sweep efficiency during EOR processes. These methods include the use of certain patterns, as well as horizontal or deviated wells. The goal of these processes is to create an even movement of injection fluid across the reservoir. Special chemicals have been used to divert the injected fluid to eliminate channeling and to improve sweep efficiency. This paper will present a new methodology to modify sweep patterns to positively impact recovery. The technique that is presented creates a mechanical barrier to flow by fracturing the formation at a strategic location. We illustrate the potential productivity increase of producing wells as a result of enhancing the horizontal and vertical sweep of the hydrocarbon. The paper also demonstrates that the combination of the barrier fractures
with other developed tools, such as inflow control devices and internal control valves, would further improve the productivity and economics of the system

The Spraberry trend of west Texas is a low-porosity naturally fractured reservoir, traditionally completed in the Upper Wolfcamp carbonate, Dean sand, Lower Spraberry sand, and Upper Spraberry sand zones. The overall interval is from 1200 to 1500 ft. thick, with completions encompassing from two to four stages. In all cases the wells require large hydraulic fracture treatments to produce economic quantities of oil and gas. The most common method of perforation selection involves correlating from well to well using cased hole gamma ray/neutron logs and drilling time. The large majority of the wells in the Spraberry trend have been perforated using this technique. The small minority of wells that have used openhole data have relied heavily on basic porosity and water saturation data to select perforations. Recent data suggest that production can be improved significantly by using VOLAN*, CFI*, and FracHite* data to select the perforated intervals. A group of 10 Dean/Wolfcamp wells that used the combination package of VOLAN/CFI/FracHite had a 103 percent increase in initial oil potential over 11 offset Dean/Wolfcamp wells that used basic openhole porosity and water saturation data. In addition, the well group with VOLAN/CFI/FracHite data produced 73 percent more oil over the initial four months of production than the offset wells. A discussion of the methodology, follows, along with the production results of the 21 wells in the study.

Multilateral horizontal wells have been used as an approach to further improve production and injection volumes. As a result, very often the steep hyperbolic decline seen in a single lateral well is reduced. The first approach used was with a milled casing section in which several laterals are drilled off a cement plug. Subsequent laterals are then sidetracked off the main laterals drilled. These laterals are 4 314 inch openhole with no liners. Reentering these laterals is costly when doing initial stimulation work for completion. Considering the future need to clean out fill or other precipitants with a bit and also to restimulate, a lower risk well design was desirable. With the help of Weatherford Enterra, a system designed using a permanent packer and retrievable whipstocks was used to address the problems and costs of finding multiple laterals. The system has considerably reduced the amount of time it takes to locate each lateral and greatly improved the likelihood of doing so at a later date.

The Permian basin of west Texas is known for its low permeability reservoirs, earning it the reputation of "hard rock country." wells completed here require A significant percentage of the hydraulic fracture treatments in order to produce economic quantities of oil and gas. The hydraulic fracture treatment can represent a significant portion of the total well cost. In addition, the effectiveness of the treatment can be critical to the economics of the well. Too small a treatment can leave valuable hydrocarbons in the ground. Too large a treatment can be equallyinefficient and possibly ruin the well. Knowledge of the rock elastic properties and in-situ stress distribution is critical to determining the induced fracture geometry. With full sonic waveform data now available, the dynamic elastic properties of the rock can be directly measured. Poisson's ratio (v) can be directly obtained from the shear and compressional transit times. From the v/(1-v) relationship the horizontal stress component of vertical overburden stress can be obtained. When this is combined with pore pressure and bulk density data a relative closure stress value can be obtained. The final product is called the FracHite* log. As of this writing, over 450 wells have been evaluated with this technique. Several single-zone and multiple-zone field cases are presented here to illustrate the applications of the technique in the Permian basin. In addition, a 2D hydraulic fracture model is used in conjunction with actual decline curve data to illustrate the specific benefits of accurate hydraulic fracture height data. The case study utilizes data from a representative producing San Andres well in Ector County. An additional item of importance is the orientation of the hydraulic fracture. This is critical to designing an efficient drainage pattern in a field. It is now generally accepted that the hydraulic fracture follows a two-wing pattern dictated by the natural stress distribution in the rock. With the eight button Dual Dipmeter* and the FILMAP presentation this natural stress distribution can be mapped with an unprecendented degree of accuracy. the Dual Dipmeter, Nine Spraberry/Dean wells were evaluated using and the results are presented on a map of Midland and Martin Counties.

For maximum profits in rod pumping operations the efficiency of the pumping system must be maximized, this can only be achieved by finding the optimum pumping mode for the required liquid production rate. These principles are used in the paper by presenting a case study on improving rod pumping operations. The project reported was conducted in a mature onshore field with 70-plus rod pumped wells. An extensive measurement program involving more than 50% of the wells was set up and pumping parameters were measured with a portable computerized system. The detailed evaluation of measurement data facilitated the detection of general and specific problems. With the aim of improving the field-wide profitability of pumping operations, an optimization of each well's pumping parameters was made. Calculation results showed that a field-wide power saving of about 17% can be anticipated if all wells operate at their most economic pumping modes.

Carbonate formations are often stimulated by hydraulically fracturing the zone of interest with reactive fluids, most commonly hydrochloric acid. The productivity increase of the oil and gas wells where this stimulation approach is utilized, is often much less than predicted by the pretreatment design. This paper will address the problems and difficulties of properly designing an acid fracturing stimulation treatment, and will offer new techniques and alternative fluid systems that allow better designs for this type of stimulation. These new methods and fluids have recently been applied to achieve extended fracture penetration of live acid into carbonate formations, allowing higher sustained production. Results of treatments where the new designs have been utilized throughout the Permian Basin will be included as case histories.

Increase the return of your investment! Naturally, everyone is interested in doing this. The object of this paper is to discuss some recent developments of accessories which may be adapted to your present sucker rod pump which will make it better suited for the well condition. All of these accessories may be adapted to most of the conventional sucker rod pumps, and will increase their efficiency or service life, thus increasing the return on your investment.

As a result of increasing emphasis on cutting waste, streamlining operations and improving recoveries, the use of the short cycle adsorption unit has become a widely accepted method of processing gas streams.

The production of high gas liquid ratio (GLR) wells has been a problem for oil producers since the first sucker rod pumping systems (SRPS) were installed. This paper examines three key factors in improving SRPS efficiency in high GLR wells. These include pump design, rod string stability and field operations. Although pump design and field operations are well documented, an attempt is made to clarify these areas. Also, new light is shed in the area of rod string design with special consideration of rod buckling and its associated problems.

This paper describes field implementation of a newly-developed downhole injection @I-II) tool for same-well-bore, simultaneous-gas-production-and-water-disposal, for water drive oil and gas formations with water coning problems. The method enhances the production rate of water-free gas while minimizing disposal cost and eliminating problems associated with water disposal. (Fig. 1)

The accurate determination of residual oil saturation is of critical importance in evaluating the feasibility of applying an enhanced recovery process in a specific reservoir. The economics of the new improved recovery processes are extremely sensitive to the residual oil saturation in place at the beginning of the project and to the conformance expected to be achieved within the project area. This means that both the amount and the distribution of oil remaining in place must be determined to adequately evaluate the potential of the venture. The only accurate means of determining the residual oil saturation is to measure it in situ within the reservoir zone of interest. In recent years, several methods have been developed to provide this measurement, including analyses of cores cut with a pressure core barrel, various advanced logging techniques, and the single-well tracer test. Each method has certain advantages and limitations, but field experience has shown that some methods are clearly superior to others. However, for some reservoir situations, one method may not provide all the information required to completely define the distribution and amount of remaining oil. These cases might require the application of two or more methods combined with an analysis of all available reservoir data. This paper will briefly summarize several procedures for determining residual oil saturation and. as pertinent, outline the advantages and limitations of each technique. The single-well tracer method will be described in more detail in terms of two recent field applications.

Incident at Morales involves a variety of ethical issues faced by a company that wants to quickly build a plant in order to develop a new chemical product to gain a competitive edge over the competition. This 36 minute video developed and distributed by the National Institute for Engineering Ethics will be shown.

The accumulation chamber is an efficient method of oil production by gas lift. The fundamental purpose of the chamber is to provide additional storage space in the well bore during intermitting gas lift operation. Various formulae are offered for the calculation of chamber design. It is shown by theoretical analysis, supported by field data, that the use of the gas lift chamber principle improves production.

In the reaction of formation rock with acid, as in a matrix acidizing treatment, varying quantities of insoluble fines are released or otherwise dislocated by the flow. Also, normal reservoir flow can break or dislodge fragile clays and minerals present on the pore linings. If allowed to settle and accumulate, these fines have the capability of plugging pore throats when disturbed in mass upon the return flow of the treatment and formation fluids. The addition of a silt suspending additive to the acid used for treatment will prevent this accumulation by keeping the fines distributed in this fluid, thus preventing plugging while removing them from the formation. A silt-suspending system that uses an electrostatic repulsion approach to fine suspension is discussed. Laboratory work describes the system's properties in relation to oil reservoirs and field data shows the system's usefulness. This treatment has been successfully used in well workovers to remove existing clays, fines, and precipitated solids. Production data on this aspect is presented.