Market competition, shareholder returns, declining product price, technology, safety and environmental legislation continually challenge the oil and gas industry. An additional challenge faced by many oil and gas producers is effectively maintaining equipment to acceptable levels in order to sustain production targets. Asset reliability has become a focal point of discussion both domestically and internationally. Asset reliability can become a significant liability to the owner if the equipment is not in a state of production readiness or if an unforeseen catastrophic safety or environmental event occurs. Many industry leaders are successfully meeting the challenge by adopting reliability based asset management. Today, industry organizations have successfully aligned their business plan with reliability management. The results are very impressive. This paper will examine common threads, which tie reliability asset management with corporate business goals.

This paper describes an analytical procedure for forecasting the life expectancy of rock-bit journal bearings. Actual performance data and reliability analyses are used to establish empirical relationships and graphs that relate risk of bearing failure to operating parameters and drilling cost. The paper was originally published in SE Drilling Engineering, June 1990 (Volume 5, No. 2).

This paper describes an analytical procedure for forecasting the life expectancy of rock-bit journal bearings. Actual performance data and reliability analyses are used to establish empirical relationships and graphs that relate risk of bearing failure to operating parameters and drilling cost. The paper was originally published in SE Drilling Engineering, June 1990 (Volume 5, No. 2).

Paraffin and/or Asphaltenes, present in all oils/condensates, are responsible for damaging a majority of wells in the United States. Increasing production from these wells can be accomplished by removing the organic damage but the increase may be of short duration unless new damage is prevented. Squeeze treatments using paraffin and asphaltene inhibition chemicals have successfully held oil and gas production increases at elevated levels following stimulation by keeping new damage from reoccurring for greater than six months. The extended high levels of production are needed to pay for cost of the sometimes, large treatments required to clean and squeeze the wells. This paper will describe the types of damage possible in flowing wells, pumping wells, CO2 floods, water floods, and gas floods. Cleanup and Squeeze treatments will be described and case histories presented of successful treatments.

Sedimentary formations are the usual target for oil and gas exploration. Of the many classifications of these zones, carbonate and elastic deposits most often bear hydrocarbons in commercial quantities. Clastic formations are composed of broken and fragmented pieces of older existing rocks. Sands or sandstones can be classified as elastics. They result from erosion and weathering of land masses. The eroded particles are transported by various means to an area of deposition where they are laid down in somewhat orderly strata. Carbonate rocks result from the precipitation of minerals held within an aquatic environment. Carbonates are formed of varying concentrations of calcium and magnesium carbonates. Most texts represent sedimentary rocks as orderly strata arranged in uniform distribution. It is very important to remember these zones are actually composed of numerous individual grains of fundamental makeup materials. The size, shape and homogeneity of the matrix greatly contribute to a formation's ability to store and later transmit hydrocarbons. For the purpose of this discussion, any change in the potential for production caused by foreign fluid exposure will be classified as formation damage. There are four primary formation damaging mechanisms commonly recognized in most sedimentary hydrocarbon bearing zones. These mechanisms are (1) the hydration and swelling of formation clays, (2) the invasion and/or migration of solids into and within the formation, (3) the formation of water blocks, and (4) the formation of emulsion blocks. The damage resulting from any one of these sources can be seriously detrimental to well productivity as well as extremely long lasting. The prevention of these types of damage is much less involved than rectification after damage has occurred.

Information essential to interpretation of hydrocarbon and/or water productivity is not available from a single measurement technique, whether it be core analysis, complete suites of electrical logs or bottomhole pressure build-up or fall-off tests." The best features of each technique can be combined to obtain mutually consistent interpretations which result in improved evaluation of potentially productive intervals in a well. Methods are described which combine core analysis data with electrical resistivity logs. This combination yields information required to select zones for completion, zonal producing characteristics and their possible down-dip productive limits. To accomplish this, core analysis and appropriate reservoir fluid data are converted to values of resistivity. These values are plotted on transparent overlays which are compatible with resistivity scales reported on the downhole resistivity log.

Dehydration and of the proppant crushing inside the fracture, are the two damage mechanisms mostly recognized as the main contributors to the overall reduction in fractured well productivity. Fracture face damage caused by the fracturing fluid loss through the four fracture faces also creates additional pressure drop that may further reduce the effective wellbore radius. The magnitude of the effect depends on reservoir characteristics, fracture geometry, extent of fluid leakoff into the reservoir, and the viscosity of the fracturing fluid filtrate. A step-by-step approach to predict the fluid loss through the fracture faces during the fracture treatment is explained in this paper. The depth of penetration through the fracture face and the resulting skin values for both the wall building and viscosity controlled leak-off model are determined. This study employs a simple approach that is based on the work of Cinco-Ley & Samaniego that assumes that damage through the fracture face is only caused by fluid saturation changes. The production-forecast simulator used to analyze the effect of various fracture face skin values on oil and gas well productivity agrees with Cinco-Ley and Samaniego study that shows the effect on the effective wellbore radius is negligible when skin value is less or equal to 0.1. In general, the study shows that fracture face damage has a negative effect on productivity only during the wellbore storage and fracture linear flow period. The magnitude of pressure drop increases with increase in reservoir permeability, damage ratio and fracturing fluid leakoff-viscosity.

All types of machinery such as generators, process machinery, forges, machine tools, etc., are mounted on rigid and heavy foundations. The pumping unit is no more nor less than a piece of machinery designed in such a way and with suitable capacity to move a string of sucker rods up and down in a well thereby actuating the pump. In order for this machine to operate properly and give satisfactory service, it must be mounted on a suitable foundation.

Literature examples of the calculation of permeability and fracture length from the square root of time plot usually involve single phase flow. This paper discusses (1) fracture analysis based on multiple phase flow, (2) use of the slope of the linearity and the end of linearity for permeability and fracture length calculation, (3) what is the end of linearity and (4) problems in drawing the proper linearity in a square root of time plot.

The successful design and implementation of any improved oil recovery project in a fractured reservoir depends on an accurate characterization of the fracture system. This is especially true in a steam pilot project currently underway in the Yates Field of West Texas. This pilot will assess the economic viability of accelerating gravity drainage in the gas cap of the fractured San Andres reservoir. From the conceptual phase of the project through implementation and monitoring, fracture characterization in the pilot area has been critical to pilot design and success. Key decisions have depended on an accurate assessment of fracture density, orientation, flow capacity and connectivity to other portions of the reservoir. Many geologic and engineering methods have been employed to understand the fracture system. Flexure mapping, tracer testing, pressure interference testing and reservoir simulation were employed in the design phase of the project. Fluid sampling and passive microseismic monitoring have been employed to monitor the project. This paper will discuss each of these methods, field results, and key decisions that were based on the analyses.

Natural fractures existing over a regional area have long been known to dominate all aspects of performance in the Spraberry Trend Area". However, there is little or no information on the actual fracture system other than: orientation, on a gross basis, from pulse and/or tracer tests in the 50's and 60"s, and fracture spacing inferred from simulation and a few existing vertical cores. Previous descriptions and old core reports did not distinguish between natural and coring induced fractures, thus almost all information from the early years, when almost all Spraberry data was obtained, provides no detailed information on the natural fracture system. The first vertical core, taken as part of the current program in 1993 from the Shackelford Spraberry Unit #l-38A, intersected a vertical natural fracture with significant mineralization that had clearly grown into unoccupied space. This open, mineralized fracture was contained within a thin pay sand and was observed to terminate at a shale parting. This fracture was the first documented evidence of the existence of mineralized natural fractures within the pay sand. The orientation, containment within zone, degree of mineralization, fracture aperture and spacing are important questions when considering fluid flow in naturally fractured reservoirs. However, after considerable data gathering, it became apparent that only superficial characterization of the natural fracture system was available. Recent acquisition of the horizontal core has radically altered understanding of the natural fracture system in the Spraberry Trend Area. This well, the E.T. 0" Daniel #28, was cored with the intent of intersecting natural fractures in the thin sand streaks where oil saturation is found in the Upper Spraberry. Over 100 natural fractures were intersected from the 1U and 5U pay zones exhibiting an intriguing and diverse array of fracturing behavior. This paper describes the coring operation, fracture analysis of the cores and log analysis from the horizontal wellbore.

Passive seismic measurements were taken before, during, and after a fracture stimulation treatment to monitor the fracture growth and optimize future fracture treatments. The seismic events created by the fracture treatment showed an asymmetrical east-west trend during the treatment, with wide variations in the locations of events. The passive seismic measurements support the previous belief that the fracture orientation for the field is east-west. However, the recorded events showed more complexity to the fracturing process than had been anticipated. The events showed a southwest trend toward a producing well along with the widely scattered events to the east. Neither, the 3D fracture simulator, pressure transient analysis, nor production injection data supports the very large fracture geometry of the passive seismic events. Fracture lengths and heights from the passive seismic events varied along with the directions. The length of the wing to the southwest showed seismic events over 1200 feet from the well, while the east wing events only reached about 700 feet. The different wings also showed a large variation in the height of events. Although the treatment interval was 4820-49 10 feet, seismic events occurred Tom 4550-4900 feet for the southwest wing and 4600-5008 feet for the east wing. The shorter length to the east is believed to be due to the well being offset to the east, by another injection well. The higher pore pressure, from the water injection, caused the fracture pressure to increase, thereby changing the direction of growth of the fracture. The passive seismic results show that fully modeling the fracture process will need to incorporate a simulator that allows varying fracture parameters aerially as well as vertically. The 3D model, of the initial 1966 fracture treatment, showed a propped fracture length of 139 feet, with a propped area of 29,000 square feet, The prefracture falloff, which followed running a liner and a cement squeeze, showed an area of 15,000 square feet. The second 1995 treatment model results gave a length of 150 feet and an area of 26,000 square feet. The values for the last job match very closely the pressure transient results following the treatment, of 24,000 square feet, showing that the current model can predict fracture results adequately for most evaluation purposes. However, for non-uniform pressure gradients a more detailed area1 model will be needed.

A novel process has been developed to reduce the polymer damage associated with aqueous fracture treatments inclusive
of the filter cake and polymer residue and their detrimental effects to fracture conductivity, formation permeability,
and the resultant oil and gas production. This novel approach differs from conventional breaker applications in that the
formation is first treated with breakers and then the fracture treatment is performed. The process advances that a
"Fracture Pre-Treatment" fluid enriched with breakers is pumped ahead of the primary fracture treatment and proppant.
The process also advances that the breakers coat the formation matrix to include the formation surfaces, pore throats,
and permeable network through natural leak-off prior to the dynamic deposition of the filter cake during the fracture
treatment.
Since the breaker enriched Fracture Pre-Treatment fluid is pumped prior to the main body of the fracture treatment
(and proppant), the dynamic pressure differential between the fracture and the formation contains the Fracture Pre-
Treatment fluid behind or in the formation during the fracture treatment. Thus the main body of the fracture treatment
is unaffected by the Fracture Pre-Treatment fluid. The fracture treatment is completed in the conventional manner with
standard breaker concentrations, the well is shut in to allow the fluid to break, and the flow-back process is then
initiated. During the flow-back of the treatments the pressure dynamics are reversed releasing the fracture treatment
and Fracture Pre-Treatment fluids. The breaker enriched Fracture Pre-Treatment fluid flows from the formation matrix
into the fracture sweeping it with a concentrated breaker solution.
This unique process concentrates the breakers on the formation side of the filter cake, increases the total mass of the
breakers that can be applied and further exposes the filter cake and polymer residue to the breakers upon flowback of
the fracture treatment and Fracture Pre-Treatment fluid. These combined factors enhance the degradation of the filter
cake and polymer residue, thereby promoting increased regained fracture conductivity, formation permeability, and
further enhancing oil and gas production.

In recent years several papers have been written on the merits of fracture stimulation with crosslinked methanol. While crosslinked methanol has been available to the industry since the late 1980"s, only in recent years has it been successfully and routinely utilized in the Permian Basin. This paper will discuss the fluid system, with focus on recent system refinements, while special attention will be paid to the development of standard procedures implemented to ensure methanol is pumped safely. An overview of the reservoirs where crosslinked methanol has been applied successfully, along with treatment parameters, will be discussed.Finally, a production study of case history wells relative to offset Morrow producers will be reviewed.

Approximately 20% of all fracture stimulation treatments in Conoco Inc.'s Odessa, Texas production area experienced problems which resulted in less than optimum frac jobs. Close examination of these treatments indicated that poor quality control was the primary reason for the problems experienced. To improve the quality control, guidelines were generated by engineering, field and service company personnel that 1) evaluates the service and safety performance of the treating company, 2) evaluates the design itself, and 3) discusses areas for improvement in subsequent jobs. Since inception in June, 1984, use of the program has spread from one production area to five areas and 48 jobs have been monitored. Misinterpretation of the job procedure has decreased since engineers are submitting more specific and workable procedures. Also, the service has significantly improved since the project quality control program was implemented. Overall, monitoring all phases of the project in an organized manner has resulted in higher quality performance.

Multi-stage proppant fracture treatments are routinely applied to stimulate discrete formations and, more recently, distinct sections (stringers) within a formation to maximize the production of these finite zones. One method consists of perforating a zone, pumping a crosslinked pad, proppant-laden fluid; and acid followed by a gelled flush. A subsequent stage is then perforated, isolated and the process repeated. Multi-stage fracture treatments have been optimized by the use of highly efficient perforating techniques that perforate and isolate zones in less than 30 minutes. Further, a novel approach has been developed that minimizes the total treatment volume by approximately 200 bbls per stage where six to eight stages are common. This paper will describe the perforating technique, the approach that reduces the treatment volume and will quantify the cost savings associated with the reduced volumes. Minimal friction pressures encountered in resuming pumping will also be quantified from actual job reports. Benefits such as the reduction of polymer damage will also discussed.

This paper focuses on the various stimulation designs and treatments performed during the development of the Pecos Slope Field in eastern New Mexico. Information collected from over 125 wells has been categorized and studied in an attempt to determine the best possible stimulation technique for this formation. The Abo sand is a noncontinuous, lenticular, "tight gas" formation which has made evaluation of treatments difficult due to the manner in which these sands were deposited. The evaluation of various stimulation techniques has been summarized by means of calculated skin factors, K, Kh, CAOF and percent decline in the first three months of production. This evaluation will help to determine the preferred fluids, volumes, sand concentrations, rates and other aspects which may or may not play a role in the success of stimulation treatments in this area.

The theory of low fluid loss fracturing is presented. The fluid loss properties of current fracturing fluids are shown by a demonstration of the API test method. Fluid loss test results are interpreted in comparing fracturing fluids.

Since 1949 when the first fracturing treatment was conducted using a Naplam gel and a very small quantity of sand, significant advances have been made in the state of the art concerning fluids to be used in carrying proppants into fracture systems. Up until the late 1960's, the basic fracturing fluids went through a transition stage from the Napalm type gel to crude oils, condensates, and then to water based fluids. Eventually, the aqueous fluids were viscosified using starch, then finally to guar gum and cellulose derivatives. Viscous diesel and crude oils were also used. Crude oils and diesel fuel were thickened using fatty acids and caustic; creating a soap like material which adequately carried proppants. There was some use of oil external emulsions but these were limited due to high friction pressures. The only real variation in the type of fluids related to concentration of viscosifying agents which subsequently controlled proppant transport and viscosity of the fluids in the fracture systems. Some advances were made in degrading agents; i.e., internal breakers during these periods. But basically the fluids used up until that time were simply thickened fluids used to pump proppants back into the fracture systems which were controllably degraded and released. Some of the more obvious disadvantages of these fracturing fluids were: (1) High friction pressure required to pump these fluids (2) Low temperature stability (3) Vunerability to shear (4) Downhole viscosity dependent upon surface viscosity If high viscosity was required downhole at elevated temperatures, an extremely viscous fluid was needed on the surface. This could cause serious problems in regards to hydraulic horsepower requirements and pressure limitations on the surface. There were significant improvements during these years on the types and quality of thickeners, friction reducers, etc. However, basically nothing new in the art; i.e.breakthroughs yielding more temperature stability downhole or more efficient use of hydraulic horsepower were present.

Crosslinked gels are adequately stable at high fluid temperatures and have thus established their usefulness for fracturing high-temperature formations. However, in certain treatment situations, they may develop high friction pressure in tubular goods which can limit their injection rate. Furthermore, the rheological properties exhibit a time-shear history dependency that is quite difficult to predict. Two-stage gel systems have been very successful in providing a means to develop desired viscosity at downhole conditions without causing high tubular friction pressures. However, several currently available systems do not have the stability required for large volume treatments at temperatures above 250_F (120C). A fracturing fluid has been developed that solves many disadvantages and limitations of both crosslinked and two-stage gel systems. This is made possible by the use of a new delayed hydrating gelling agent. The fluid has the desired two-stage viscosity qualities and can be formulated to provide the desired viscosity throughout a treatment. In addition, the rheological properties of the new fluid system are highly predictable. This fracturing fluid system has been successfully tested in the field. Fluid design and treatment results will be presented.

The A & B zones of the Trading Bay Oil Field, Cook Inlet, Alaska are a series of heterogeneous, largely unconsolidated sandstones. These sands contain several million barrels of reserves. Although numerous attempts had been made to produce these zones since 1967, less than 1% of the oil-in-place had been produced by January, 1980. Wells which were completed in the A & B intervals typically tested at non-commercial producing rates or declined to uneconomic rates within a year. Re-perforating, acidizing and various flushes with oil, all proved unsuccessful. Extensive analysis and studies of reservoir fluids, core material and production characteristics resulted in isolating the cause of the producing problems as a formation fines movement problem. Use of various clay stabilizing chemicals met with no success. Conventional formation fracturing to stimulate production appeared to be out of the question because of the problems of proppant imbedment in the soft, dirty sandstones. However, a concept to fully pack created hydraulic fractures with high concentrations of proppant and modifications of conventional fracturing procedures to achieve it, appeared promising, was pursued, and found to be successful. This paper describes a fracturing technique including procedures and materials for poorly consolidated sandstones. The stimulation technique has resulted in successful completions in the A & B zones and made possible economic recovery of a significant and heretofore essentially non-producible resource. It is expected that the technique may be applicable in many other areas where economical drainage of oil deposits from poorly consolidated sandstones is presently not possible.

The tremendous energy of a nuclear explosive and the very small size of a nuclear device warrant consideration of utilizing the energy released to stimulate production from relatively non-productive petroleum and natural-gas reservoirs, and from oil-shale and tar-sands deposits. Significant quantities of petroleum and gas are present in many thick, deeply buried reservoirs that have natural low productivity because of low permeability of the formation or high viscosity of the oil. Productivity from such formations cannot be adequately stimulated by conventional techniques of well completion. Also, vast deposits of oil shale lie too deep for economic mining. If these deposits could be adequately fractured the kerogen present might be converted to shale oil through in situ retorting. Studies of the feasibility of using nuclear explosives to produce fluid hydrocarbons from petroleum, natural-gas, tar-sands, and oil shale deposits have resulted in the following conclusions: 1) low-productivity natural gas reservoirs off the best immediate possibility for nuclear stimulation; 2) some petroleum reservoirs may be stimulated similarly; 3) nuclear fracturing of oil shale may permit in situ retorting; 4) conclusions concerning nuclear stimulation of production from deep tar-sands deposits in the United States cannot be drawn because of inadequate knowledge of their occurrence; 5) an actual experiment is needed to determine technical and economic feasibility; 6) radioactive contamination of hydrocarbon fluids is a problem that can be solved by various means, and nuclear stimulation can be conducted safely and within existing regulations; and 7) a test may be proposed and conducted relatively soon on a natural-gas reservoir of low productivity.

This paper documents 8 years of performance of an improved artificial lift system installed in a secondary recovery project. This improved artificial lift system matches a Fiberglass-Sinkerbar rodstring design to a specific pumping unit installed with a Pump-off Controller. Fiberglass-Sinkerbar rodstring designs have been given little or no consideration concerning reduced downhole rod and tubing failures or power consumption costs. The success of this improved artificial system has led to the following improvements in field performance: 1.Increased lift capacity from 20 cmpd (126 bfpd) to 100 cmpd (629 bfpd) 2.Runtimes between failure in excess of 1450 days (4.2 years) 3.Reduced power costs from .070 to .061cents/barrel 4.Lower operating expenses due to reduced power consumption, reduced maintenance costs and less downtown. Utilization of this improved artificial lift system will increase lift capacity, reduce downhole failures, increase runtimes and reduce power consumption and related expenses

Tubing leaks due to rod wear and corrosion are common in the oil field and can add significantly to the operating cost of any well. The preferred field applicable approaches to finding production tubing weak spots and leaks vary with different companies and range from pouring paint from a bucket, hydrostatic testing, and electronic inspection of the tubing as it is tripped. We have taken field data from numerous jobs and explored how each of these testing methods can be improved or enhanced to increase information reliability and to reduce the frequency and cost of well failures. Caveat: It is not the purpose of this paper to review or judge the attributes of the various techniques and apparatus used in electronic tubing inspection services as the equipment varies in how it works and how it is built. This paper addresses how the on-lease technology is applied over the well and how the results can change based on field applications and interpretations.

This study was performed at Mobil Salt Creek Field Unit in Kent County, TX and consisted of mechanical seal failures for Bingham split case centrifugal injection pumps. For individuals who are unfamiliar with the operation or function of mechanical seals, a reference is included in the study (see Appendix A - Fundamentals of Mechanical Seals). Due to the injection of C02, in addition to water, into the Mobil Salt Creek reservoir for increased oil production, the associated composition of the reservoir water changed greatly. The total suspended solids (TSS), total dissolved solids (TDS), pH, and entrained gases in the produced water changed dramatically from the former water flood or water driven reservoir. Consequently, when there were any changes in pressure or increases in temperature, solids, scaling, or "salting" was occurring. This increase in temperature or pressure drop can be quite common when dealing with the mechanical seal system. The mechanical seal system consists of three (3) items. Those items are water composition, seal material selection/design, and seal flush system. This brought to light the complexity of the mechanical seal issue.