The younger Permian carbonates have been prolific producers over the years. The San Andres and Grayburg dolomites, which are productive in nearly all areas of West, Texas, are of particular note. Although traditional log analysis has been generally successful in these reservoirs, the presence of gypsum in many has created difficulties. Gypsum tends to result in overly optimistic porosity calculations and also tends to restrict permeability by plugging the pore throats. This paper explains some of the difficulties encountered when using traditional log analysis techniques in gypsiferous reservoirs and shows how Schlumberger's ELAN log interpretation program has been used to give superior results.

Hydrogen sulfide gas is encountered in various petroleum operations, from the drilling operation through to and including the refining process; therefore, we must be aware of its properties, its toxicity and how to circumvent employee exposure to the acidic gas.

Direct Liquid Phase Oxidation Processes (DLPOP's) are a group of processes that remove hydrogen sulfide (H2S) from gas streams by absorption in an alkaline aqueous solution. The absorbed H2S is converted to elemental sulfur through the action of a metal catalyst complex contained in the solution. These processes are very effective, being able to remove H2S to below the limits of detectability when required. They are almost totally selective for H2S, with respect to carbon dioxide (C02). They are used to treat hydrocarbon streams directly, to recover sulfur from amine acid gas streams, and as tail gas cleanup following Claus sulfur recovery systems. Because they can remove and recover H2S to below detectable limits, these processes have become more important to oil and gas producers as environmental regulations have lowered emission levels for H2S, and its combustion product Sulfur Dioxide (S02). New or modified DLPOP's are being developed very rapidly. Each new process announced has some claim to reduced side reaction products, reduced operating costs, reduced capital costs, improved sulfur quality, or to improved operability. Each process is protected from full disclosure of design and operating information by secrecy agreements with the company that holds the patent.

The Harbison-Fischer patent-pending Sand-Pro

The first use of a through-tubing technique to selectively remove hard and inert scales in West Texas proved successful. The technique incorporates an abrasive jetting technology that uses two new coiled tubing tools and pumps specially manufactured particles through nozzles in a rotating head. The goal was to remove an inert scale, predominantly barium sulfate, from the production tubing in an old gas well in order to deploy tubing cutters as close to the packer as possible. The engineering and actual execution of this project are examined here. The results are compared with the previous attempt to clean out the well and an offset well to show the economic value of the technique. The subject well is located just south of Mentone, Texas, in a field that is notorious for barium sulfate scale production.

Production tubing string failure and rod failure contribute significantly to the lifting cost of some wells produced by rod pumping and in some instances, may even be a determining factor in the decision to discontinue producing a well. This paper deals with the design, installation and field testing of a polyethylene liner for production strings in rod pumped wells. The paper reviews the causes of rod and tubing failure in production strings of wells produced by rod pumping, suggests polyethylene lining as a possible solution for those failures, and provides details, through a case history, of the results of field testing.

Heated acids have been used extensively with excellent results as shown by field data and laboratory tests. A primary use of heated acids is to increase dissolution and reactivity in relatively cold formations for improved flow capacities in, for example, cold dolomites. This aids treatment (1) technique effectiveness by increasing the acid reaction rate, (2) removing acid retarding materials such as oil, asphaltenes, and paraffins from formation surfaces for a better acid-formation contact, (3) helping prevent the precipitation of organic materials from oils that have been cooled by acids, and (4) limiting temperature contraction of tubing during a treatment. On acidizing treatments conducted during the winter , acid temperatures can be less than 32_F. The effectiveness of these treatments can be improved by heating the acid and thus avoiding the problems of slow reaction rate,-precipitation, and tubing contraction. Three general acid heating techniques are used: (1) an exothermic chemical reaction with a portion of the acid as one of the reactants, (2) adding live steam to the acid, or (3) using hot oilers to heat the water portion prior to dilution.

Whipstock plugs provide an essential tool for deviating from the primary hole direction to sidetrack an impenetrable object such as drill pipe or bit, or to initiate a planned hole deviation to complete a lateral or multilateral hole. The successful setting of whipstock plugs and the completion of the sidetrack operations can be very intricate, complicated by high slurry densities, high viscosities, and very low to very high bottom hole temperature extremes where costs escalate with each attempt. The whipstock slurry design should balance the requirement for adequate thickening time with the minimum time necessary to develop sufficient compressive strength for dress-off and kick-off and the rheological characteristics suitable for mixing and placement. In addition compressive strength should not deteriorate or retrogress during the time necessary for dress-off and drill-out. This paper will describe the specific design of whipstock slurries applicable in a wide range of temperatures (80F to 300F).

High Density custom designed pull through polyethylene liner programs for new and existing steel pipelines started in Canada in the late 70"s. High pressure salt water injection steel pipeline buried 6 to 7 feet deep in Northwestern Alberta prompted a major manufacturer of HDPE pressure pipe to try custom sizing a thin wall liner pipe. Custom tooling first had to be programmed to the front of the pipe extruder at the plant to fit all the various steel sizes and wall thicknesses. Once this was done the technology came along to install the system inside existing steel pipelines for renovation of the pipeline. This system development was the start of pipe rehabilitation for pipelines buried and suffering from internal corrosion. The polyethylene plant made the outside diameter of the thin wall liner pipe 2 to 5% smaller than the inside diameter of the steel pipeline inside diameter. Excavations where dug at each end of a section of the pipeline (normally 2,500 to 3,000 ft). Modified steel flanges were welded at each end to house a custom liner flange. A weld-o-let or thread-o-let was also welded to the top of the steel line and a small hole drilled through the steel pipeline wall. This weld-o-let or thread-o-let played an important role because this first system of HDPE liners would be "expanded" against the host pipe carrier by using air, water, or gas pressure inside to expand the HDPE liner. This "vent station" played an important part in vacating the annulus of any trapped air or produced water to the atmosphere as the liner expanded against the steel pipe wall. This system came to the USA in 1981 and was perfected as the "EXPANDED LINER SYSTEM" for the oil, gas and petrochemical industry. It is still being used today as a pipe rehabilitation technology with some variations and also has applications for the water and sewer trenchless techniques. In 1986, a newer method of HDPE Poly liners entered the commercial market place with a technology that places the custom liner "AGAINST THE STEEL WALL" after its insertion. Excavations, welding steel flanges that will house a custom liner flange to tie each pull section together are the same as the previous systems. This system changes at the liner pipe manufacturing plant, however in that the outside diameter of the liner is made slightly larger than the inside diameter of the steel host pipe. This system uses a series of power driven rollers to temporarily size down the outside diameter of the Poly Liner as the winch truck pulls it inside the steel host pipeline. After it is positioned in the steel pipe line, it reverses to a snug fit. In the 90's two more systems using "AGAINST THE STEEL WALL" technology were commercially developed. The first system uses a "Folding Technique". This form is manufactured at the Poly Liner plant typically a "U-Shape" sometimes with structural reinforcement tape around the outside to maintain its reduced diameter until it is inserted. The latest newest system employs a series of hydraulic downsizing "cells" that are controlled by pressure and lubrication to reduce the outside diameter as it is inserted into the steel pipeline. It is called "PRESSURIZED DIE System"" or "PDS" . The "PDS" system is easier to change equipment from one size to other on different sized steel pipelines. It also shows great potential when dealing with different steel wall thickness from a repair or liner rehabilitation for "cement lined" steel pipelines. All of the liner systems presented here use a

The use of various metal salts and metal chelates as crosslinking materials for guar gum and guar urn derivatives has been investigated under low temperature conditions (<2OO degrees F) . To determine the crosslinkers of highest efficiency, these crosslinkers were evaluated using the criteria of maximum crosslinked viscosity yield per pound of polymer employed, relative shear sensitivity of each crosslinker and projected ease of application for each crosslinked fluid system in the field. Through optimization of crosslinker-polymer interaction involving development of a delayed crosslinker for low temperature conditions, improved fracturing fluids have been developed. The polymer loadings in these systems can be dropped up to 50% without losing fluid efficiency. The performance of the crosslinked fluid system which showed the highest efficiency was taken to the field and its performance evaluated on a number of wells and compared to other conventional systems.

Development of a 2000 horsepower fracturing pump unit has brought greater safety, more reliability, more sand pumping capacity, reduced manpower requirements, and shorter setup time to fracturing operations. The pump is a crankshaft type, powered by a 16-cylinder diesel engine, and driven through an eight speed transmission. For job control, the unit is provided with remote controls and a specialized pressure limiting system. The fluid end has been optimized for handling fluids with high sand concentrations. The paper describes the design and gives pertinent specifications of the pumping unit. Selected case histories from more than a year of operation are presented, including accounts of stimulation jobs where record-high sand concentrations were pumped. Job design considerations peculiar to the use of this large-scale pumping capability are presented.

A new high performance corrosion inhibitor was developed for oil and gas field batch treatment applications. The performance of the new corrosion inhibitor was enhanced by its superior dispersion properties. Laboratory corrosion inhibition and film coverage tests showed that new corrosion inhibitor provides better corrosion inhibition than conventional corrosion inhibitor. The new corrosion inhibitor exhibited improved partitioning into water phase due to its more stable dispersion in aqueous phase. The higher dispersibility is an indication of improved field performance. It was verified in the field test that this new inhibitor provided significantly better performance than conventional batch corrosion inhibitors.

A High-Performance Fracturing Fluid (HPF) has led to a step change in the completion process of the San-Andres reservoir in Andrews County, Texas. Recent development in fluid technology has resulted in the introduction of a unique fracturing fluid that is less damaging to the formation, has excellent proppant transportability, and requires no breakers. Despite very robust and stable rheological properties during pumping, HPF returns to its original viscosity shortly after closure with no internal breakers. The unique properties of this fluid will be discussed along with case history information. Additionally, the paper will attempt to explain well performance compared to wells in the same field that were fractured with conventional low-polymer loading borates. The distinctive properties of this fluid will be presented, along with a discussion of the retained conductivity of the fracture. Case histories of this field show better return on investment using this fluid.

Fracture acidizing and hydraulic fracturing utilizing propping agents has been used successfully in the stimulation of oil and gas wells for over 40 years. A tremendous number of these acidizing and proppant fracturing treatments have been conducted In carbonate reservoirs in west Texas. It is the purpose of this paper to report a fairly extensive program to optimize stimulation results, primarily in the Cleat-fork, but also In other west Texas reservoirs. The operator was noting declining production and wanted to institute a program to stimulate oil production but also at the same time attempt to control many of the operational problems typically encountered with proppant fracturing. The operator, when attempting restimulation, had seen little or no success over the years with many types of acidizing techniques. After several different approaches were taken in an attempt to solve the problem, we felt that utilization of high concentrations of high conductivity propping agents uniformly distributed across the producing interval was the answer to obtaining sustained productivity increases.lm7A lthough several proppant fracture treatments had been conducted in the area, we felt quite strongly that job design, job execution, and shut-in and flow-back procedures were inadequate to properly stimulate the reservoir. Our initial premise was to utilize as simple a fluid as possible, thereby eliminating job execution and fluid problems. We also wanted an efficient fracturing fluid with excellent proppant transport properties to be able to achieve a very high conductivity propped fracture. Additionally, we utilized the forced closure technique to minimize proppant settling in the producing interval. The authors felt that a major problem in the area was settling of the proppant into water-producing intervals in the lower part of the Clearfork. In the paper, we will give very specific examples of the use of intense quality control and also go into our evolution into the use of 35 lb/l 000 gal borate crosslink gels, as well as the very simple, straightforward polyemulsion system. We feel in both cases that the use of an aggressive proppant schedule, proper job design, and an aggressive flow-back schedule has allowed a very successful stimulation program to be accomplished. We will give extensive results on pre- and post-fracture productivity, as well as economics.

In the paper, we will give very specific examples of the use of intense quality control and also go into our evolution into the use of 35 lb/l 000 gal borate crosslink gels, as well as the very simple, straightforward polyemulsion system. We feel in both cases that the use of an aggressive proppant schedule, proper job design, and an aggressive flowback schedule has allowed a very successful stimulation program to be accomplished. We will give extensive results on pre- and post-fracture productivity, as well as economics

High rate rod pumping continues to be an important artificial lift method in many fields around the world. Just what are the production limits and the loads for the largest rod pumping units? A comparison of the largest convention unit, air balanced unit, an improved geometry unit. and an ultra long stroke pumping system shows the potential production limits at various pumping depths. The key element in design is not to overload the sucker rods so that frequent fatigue failures occur. Also to prevent premature failures, do not overload the unit gear box and structure rating. The common goal in selecting. installing and operating any artificial lift system is to make the highest present value profit (PVP) -- net discounted income. All factors must be considered in picking the correct type, kind and size of lift method. Close attention to the various attributes of each lift method is recommended. The designer should consider the initial installation costs, possible production rates, and operating costs. The most difficult of these factors to obtain is the operating cost for the lift conditions to be encountered. Operating cost estimates must be made for typical fixed and variable costs plus the cost for energy and pumping repair and maintenance costs. Cost data from an analog field are most beneficial. Once the designer has the basic cost data, an overall economic analysis can then be made for the various artificial lift methods. Thus, by a combination of proper selection, design, and operating practices, near maximum profits will be realized.

Beam installations using high slip motors (20 to 30 per cent range) can reduce gear box torques some 30 to 40 per cent over beam installation using conventional 8 per cent slip motors. In addition, high slip motors can reduce peak polish rod loads 10 to 15 per cent. These load reductions can mean a saving in capital expenditures plus a reduction in operating costs.

Blocking gels have been used in low temperature zones for many years. Blocking gels are employed in workover operations to isolate producing zones. The problems with isolating high temperature zones were mostly due to the insufficient or unstable rheological properties of the crosslinked blocking gels. Recent developments of unique crosslinkers, stabilizers, derivative polymers and enzymes have provided significant contributions to the oil and gas industry. The combination of these advantages has led to the development of high temperature blocking gels, which enable temporary isolation of producing zones for extended periods of time at temperatures greater than 250_F. In addition, these blocking gels can be removed at any time without leaving damaging polymeric residue. Laboratory data demonstrates the effectiveness of the blocking gels as well as their ability to clean up in high temperature zones. High Temperature Blocking Gels For Temporary Workover Operations

CO2 foam properties were measured to 300_F in a high temperature, high pressure pipe viscometer. The effects of foamer type and concentration on high temperature CO2 foam rheology were determined. It was found that, above a certain level, further increases in foamer concentration provide little corresponding increase in foam stability or rheology. CO2 foam stability can be improved by the use of higher concentrations of gelling agent. Test data indicates that higher concentrations of foamer and gellant are required to produce stable CO2 foams, as compared to N2 foams. It was found that rheological data generated for N2 foams will not be sufficient to describe the same system when pumped as a CO2 foam.

Fracture acidizing systems previously available are acid and temperature sensitive. This paper will discuss a new crosslinked acid system that is compatible with up to 28% HCl and that has been successfully pumped at bottom hole temperatures to 250_F. Fluid rheology, friction pressure, fluid loss, additive compatibilities and acid reaction rates supporting the use of this system at 50 and 60 lbs./gal. polymer loadings are presented. Computer designs for acid fracturing and reservoir simulation are included in the paper to show the effects of the stable crosslinked acid compared to other available systems. This system has been used both with and without proppant. The acid concentrations have ranged from 3% to 28% HCl and where applicable sand concentrations from 2 to 6 lbs. per gal. have been successfully placed. Field data is presented for both producing and water injection wells. -

This paper will discuss prior publications of the lift capacity for sucker rod lift method versus net effective lift depth. Additionally, the current day upgrades in lift systems and availability of larger downhole pumps will be investigated to provide current high rate lift capacity versus depth.

While operators are always searching for new techniques to produce oil more efficiently, the economic climate in which the oil industry finds itself today has renewed efforts to seek out new opportunities to improve operational strategies. This paper will discuss a field scenario in which gas locking problems were impacting production in a mature field in West Texas operated by Texaco. This field was being produced with CO2 injection and was experiencing increases in beam lift failures and high CO2 production. After reviewing the conditions, the service/engineering company suggested a change in the pump configuration to increase the compression. A higher compression rod pump is an advantage for operators especially where gas is a concern. To accomplish the higher compression, the pump was built with the least allowable amount of unswept volume between the traveling valve and standing valve. By positioning the two valves as closely as possible and eliminating as much unswept volume as possible, positive results were experienced. Eliminating gas lock and having to long stroke wells can be of great assistance in saving money for operators. This, in turn, can eliminate the use of gas breaking devices, which can be costly. The experiments with some of the Texaco Sundown Slaughter Field wells with high C@ production have shown improvement on efficiency and gas lock As a result, the operator will also see reduced fluid pounding, which will increase the life of the equipment in the well, and thus, provide higher efficiencies and longer equipment run times.

WellChek Database has been developed to provide a well specific, tubing string profile from an on-site used tubing inspection unit. Tubing is classified as it is pulled from the well, providing sequential information on a per joint basis within the string. Before being returned to production a detailed report of the tubing string is provided online, which can be viewed together with previous inspection results, containing critical information to the well management program. Routine well maintenance provides the opportunity for inspection data to be easily obtained. Field engineers find it beneficial to track wear and corrosion patterns, propensity, failure causes and success of mitigation techniques. Tubing issues make up a high proportion of production costs - rig time, lost production, tubular replacement and transportation. Working together with production engineering groups to analyze this data has yielded information to assist in making practical tubing management policies to reduce these costs.

Underlying part of a several county area in western Texas is the Horseshoe atoll, which will measure about 90 miles across in an east-west direction and about 70 miles from north to south. Producing from the Canyon Reef limestone at approximately 6,700 ft., which is a part of the Horseshoe atoll that underlies Scurry County, is the Sharon Ridge Canyon Unit. The Sharon Ridge Canyon Unit is a pressure maintenance project using fresh surface water injected on a peripheral pattern. The water distribution system is made up of both bare steel and cement lined pipe. A central treating plant is used, and water quality has been maintained at a high level with corrosion controlled effectively. Wells are produced to a high water-oil ratio which means continual water production of a certain amount. The produced water is gathered and returned to the reservoir through its own system. Since commencement of unitized operations the volumetric average reservoir pressure has increased 471 psi from 1,583 to 2,054 psi. Performance to date under the influence of water injection has been very encouraging, and a recovery of twice that predicted without pressure maintenance is expected.