Statistics demonstrate that there is big money in oilfield theft, approximately half a billion dollars yearly. Yet, most operators would be hard pressed to itemize their actual assets or verify ownership of stolen or lost equipment. This paper discusses the lack of internal control prevalent throughout the petroleum industry and identifies, through initiation of company policy and procedures, methods to both minimize oilfield theft and maximize cost-effective loss prevention accountability.

Waterflooding concepts in carbonate reservoirs of West Texas and New Mexico have changed drastically in recent years. The original flood designs for many waterfloods called for peripheral water injection with minimal interior injection. The use of generalized geologic correlations or averages of rock properties in the design and execution of these projects led to delayed and inefficient flood response. Review of these drive projects, particularly with a more precise geologic definition, led to the conclusion that closer-spaced, more regular flood patterns would be necessary to enhance ultimate oil recovery.

Infill drilling in conjunction with waterflooding is being used to accelerate production and improve recovery efficiency. Many authors have discussed the reasons for infill drilling and the factors which affect the success of an infill drilling project.I,2,3,4,5,6 Reservoirs are heterogeneous rather than homogeneous. Van Everdingen1 related this to spacing and infill drilling. He noted that the East Texas field has been developed on a five-acre spacing. Recovery in this field with close spacing will be about 87% whereas other fields usually average 30%. He studied a number of fields, both carbonates and sandstones, and noted that recovery efficiencies improved as acre-spacings decreased. Barber et al2 discussed the carbonates in West Texas. They reported that the reservoirs were found to be more discontinuous than originally thought as more wells were drilled. In the Fullerton Clearfork Unit infill wells were drilled and some producers were converted to injectors. The infill wells produced higher rates with lower water cuts than the offset wells. This was interpreted as additional pay being opened up with some of the pay not having been flooded. Thus, infill drilling increased reservoir continuity which they defined as the percentage of pay that is continuous from one well to the next. Driscoll3 reported on the factors affecting increased recovery after an infill drilling project. The one which ties in with our study is minimizing lateral discontinuities. Often a producing section will contain many pay zones which are vertically separated. In addition, these zones are often not continuous in a lateral direction. Closer spacing increases the percent of continuous pay.The discontinuities are particularly evident in carbonates. This is also evidenced by the waterflood pattern used with a reservoir. Ghauri et al note that in the West Texas Denver Unit initially a peripheral injection was used. However, because of the discontinuous zones, much of the reservoir was not being flooded. According to Stiles5 there are three requirements for a pay zone to be successfully waterflooded: a) Continuous and homogeneous between injector and producer b) Injection supported c) Effectively completed in offset producer. Obviously, discontinuous zones will have some difficulty meeting the first and third requirements. George and Stiles reported on the Robertson, Fullerton and Means fields They noted that these fields have many porosity stringers over several hundred feet of thickness. Some of these stringers are continuous over several thousand feet while others extend only a few feet. Rarely does one stringer cover the entire field. In addition, thicker formations such as these are more apt to have several permeable layers.

This paper presents oil-water inflow performance relationships (IPR) for water drive reservoirs above the bubble point. A wide range of rock and fluid properties, relative permeability curves and initial water saturations has been considered. The effect of a skin region around the wellbore is also included in the analysis. The general theory and application of pressure-production relationships have been discussed.

This paper presents oil-water inflow performance relationships (IPR) for water drive reservoirs above the bubble point. A wide range of rock and fluid properties, relative permeability curves and initial water saturations has been considered. The effect of a skin region around the wellbore is also included in the analysis. The general theory and application of pressure-production relationships have been discussed.

Over 40 years ago, the late President Hoover set forth a creed which is perhaps even more applicable today than when he said: "It is only through the elimination of waste and the increase in our national efficiency that we can hope to lower the cost of living, on the one hand, and raise our standards of living, on the other. The elimination of waste is a total asset. It has no liabilities."" This is the creed by which we in the oil industry are trying to live when we attack the problem of corrosion losses or waste in oil and gas producing equipment. A cynic might say that we in the chemical industry are merely trying to increase our sales and profits while you in the producing industry are merely trying to reduce your lifting costs thereby increasing your profits. Such a statement would be true, of course, and what better way is there to "increase our national efficiency?"

The Injecta-Box

The Iatan East Howard Field is located in eastern Howard County, Texas. Production is commingled from the San Andres, San Angelo and Clearfork zones. Pressure support in the field is provided by waterflood. Injectivity into these zones was poor due to the buildup of iron sulfide and biomass. Several methods were used to cleanup this buildup. The first method used was to cleanout the wellbores with 15% acid and 14% sodium hypochlorite (bleach), utilizing a coiled tubing unit. The second method was to pump bleach and acid into the injection system, which would in turn be pumped down the wells. The third method was to cleanout both the surface and downhole lines with 3000 parts per million (ppm) chlorine dioxide (CL02) and 15% NEFE acid. The relative benefits and costs of these three methods is discussed. This work was performed when ARC0 Oil and Gas (ARCO) operated the properties. In the fourth quarter of 1992, Anadarko purchased APCO's interest in the properties. It is not the objective of this paper to discuss the chemistries and chemical reactions involved with these methods. Those can be found in numerous places in the literature. The objective is to communicate the procedures involved, the costs, and the benefits.

An innovative patented casing plunger offers production increases in Panhandle reservoirs. Several years ago, casing plungers were introduced to Panhandle oil & gas reservoirs. While several applications responded well, others were limited by wellbore conditions and reservoir fluids. Those problems have been addressed in a recently patented casing plunger, providing substantial increases in daily production and recoverable reserves. Design details, working models and producion data will be presented to encourage broader applications of casing plungers as reserves and bottom-hole pressures continue to decline. Current applications have been successful in all weights of 4-1/2" casing tapered strings common in Upper Anadarko Basin. Wellbore fluids of all combinations of oil, gas, condensate and water have been produced with the new casing plunger. Applications for 5-1/2" casing are also presented. Reasonable installation costs and recoverable tangible assets can be expected.

During the de-watering phase of typical Black Warrior Basin coalbed methane wells, an artificial lift method is needed to produce large volumes of water yet. have the ability to handle a moderate amount of produced solids such as coal fines and frac sand. In response to this scenario, the Coleman Pump Company developed a free style jet pump with a design specific to the problems encountered during coalbed dewatering operations. The unique design of flow passages in the pump allows retrieval of a very small portion of the pump while still providing a greater than normal flow capacity. In addition. the pump does not utilize any downhole moving parts which proves advantageous in a high solids environment to reduce workover expense. Meridian Oil applied the above technology to a test well in the Black Warr Coal Project. In this well, the pump was placed in the conventional or Basin threaded production tubing using a coiled tubing conveyed, concentric string, installation technique. This allowed the coiled tubing to be utilized as a power fluid path while water and gas were separated downhole and produced to surface independently through the dual annular spaces created by the concentric design. This design also provided for easy placement and retrieval of the throat and nozzle portion of the pump by using surface pump pressure. This design package provided a significant increase in water rate which resulted in an accelerated gas production rate and an overall increase in profitability for the well.

To gain a better understanding of the significance of insert rock bits in today's drilling, it is important to review the evolutionary process of the entire rock bit development. Modern-day rock bit technology began in 1909 with the introduction of the first rotary cone rock bit. Prior to this time, the use of the rotary drilling process had been limited to soft formations because harder formations were difficult or impossible to drill using the scraping action of the drag bit. The rotary cone bit, then, enabled the industry to drill much harder formations than previously possible. However, the early designs utilized cones which did not mesh. Consequently, the bit "balled" up" readily when drilling soft shale formations. In 1925, this problem was solved with the introduction of a two-cone bit with intermeshing teeth. As the teeth of one cone passed through the grooves of the opposite cone, accumulated formation was pushed from the grooves of the opposing cone; thus, it was called "self-cleaning." The new cutting structure enabled the drilling industry, for the first time, to make hole through both soft and hard formations with a single bit, markedly reducing overall time on each well. Until 1932, the basic bearing of rolling cutter bits remained the journal-type. Many attempts were made to effectively lubricate the bearing and extend bit life. However, none were effective, and bearing life remained extremely short until the introduction of anti-friction (roller) bearings in 1932.

National-Oilwell is the Distributor for a newly patented line of Insertable Progressing Cavity Pumps. This new technology allows the producer to install and remove both the rotor and stator with the sucker rod string. The tubing string contains a down-hole seating assembly attached to the bottom, which stays in place until the tubing is removed from the well. The improved efficiencies and state of the art elastomer materials are all combined to significantly reduce the lifting costs for today's producer. These pumps have the ability to move many different fluids including: oil, water, high viscosity fluids, and fluids containing solids such as sand, coal, or formation fines.

The Downhole Dynamometer Database is a compilation of test data collected with a set of five downhole tools built by Albert Engineering under contract to Sandia National Laboratories. The downhole dynamometer tools are memory tools deployed in the sucker rod string with sensors to measure pressure, temperature, load, and acceleration. The acceleration data is processed to yield position, so that a load vs. position dynagraph can be generated using data collected downhole. With five tools in the hole at one time, all measured data and computed dynagraphs from five different positions in the rod string are available. The purpose of the Database is to provide industry with a complete and high quality measurement of downhole sucker rod pumping dynamics. To facilitate use of the database, Sandia has developed a Microsoft Windows-based interface that functions as a visualizer and browser to the more than 40 Mbytes of data, The interface also includes a data export feature to allow users to extract data from the database for use in their own programs. Following a brief description of the downhole dynamometer tools, data collection program, and database content, this paper will illustrate a few of the interesting and unique insights gained from the downhole data.

Despite preventive measures taken during the manufacture of oil field tubular goods some defective lengths are produced. Other lengths become defective as the result of damage occurring during shipment or handling, or because of service conditions to which they are subjected. Failure to detect and properly dispose of these defective lengths before failure occurs has and can become costly and dangerous.

Illustrates the installation of a free type tandem dual zone hydraulic pump. Presents operation and design of special equipment required.

A Reda pump is essentially a multistage centrifugal pump, the shaft of which is directly connected through a protector section to a submergible electric motor. The entire assembly, as a unit, is of such outside diameter that it can be installed in wells completed with standard size casing. In operating position, the unit is suspended on tubing, submerged in the well fluid, with a cable from the surface supplying electricity to the motor. The installation may be for any depth since the unit is designed to function under any submergence pressures encountered.

When it becomes necessary to put an oil well on the pump, the operator is usually faced with an investment of several thousand dollars in some means of artificial lift. By far the most successful and most generally accepted type of artificial lift is the beam type pumping unit. Many years of research and testing have gone into the design of the modern pumping unit. Advancements in metallurgy and the most up-to-date machine tools go into its manufacture. All these improvements in design and technique of manufacture are of little value in the equipment is not installed properly on the well or operated correctly. For the operator to get the most from his investment in a pumping unit, he should operate the unit as the manufacturer intended it to be used and within its nameplate rating.

In today's times of material shortages and spiraling material costs, it has become increasingly important to emphasize proper installation techniques and a comprehensive maintenance program to assure long equipment life with minimum maintenance. Of prime consideration will be a scheduled maintenance program to prevent untimely and expensive downtime, and to prevent expensive major maintenance.

The purpose of this paper is to show how the design and operation of pilot-controlled gas-lift valves have overcome many of the inherent problems of multiple completions. Within the production tubing string, multiple completed wells are no different than single completions. From a gas-lift standpoint, the main difference is that several wells producing from a common casing, have a common casing annulus gas supply. This fact eliminates the use of pressure in the annulus as the sole means for actuating the gas-lift valves.

In general, the well characteristics will govern the type of pumping completion and the selection of equipment. Various arrangements of equipment are discussed, such as two packer single string, single packer with either clipped or free running secondary string, hollow rod pumping, lower zone gas venting and triple completions. It is emphasized that attention to correct installation of all equipment will eliminate needless completion expense.

This paper will discuss the installation of High Density Polyethylene (HDPE) liners in existing cement-lined and bare steel water injection pipelines. Design criteria, economic evaluation, and HDPE liner installation details are included. Also, different types of HDPE liner systems, material properties, and internal corrosion protection will be discussed.

An instrument skid especially designed for fracturing data acquisition provides operator flexibility and choices that can help reduce costs of data acquisition and recording. The operator interface panel (OIP) associated with the skid can be viewed at the skid or can be remoted up to 250 ft distance from the skid. Information collected can be used by the on-board computer system and displayed on three screens of the OIP, or the digitized data can be communicated to other computer systems that may be on the job.

Shortly after the discovery of the Block 31 field in 1945, ARC0 Oil and Gas Company, then Atlantic Refining Company, started searching for ways to improve the ultimate recovery from the Devonian formation. Laboratory research showed that natural gas would become miscible with the crude at 3500 psi. Therefore, injection of the produced gas began in 1949. A processing plant was built in 1957 to extract liquids from the gas before reinjection. Eventually, the produced gas volume was not adequate to maintain miscibility pressure and additional gas was purchased to make up reservoir voidage. Further laboratory research showed that flue gas injection would maintain miscibility at a higher injection pressure. ARC0 began flue gas injection in the Block 31 field in 1966 at a rate of 40 to 50 MMSCFD. In 1980, a favorable decision was handed down from the U.S. Department of Energy relative to the recoupment of investments made in tertiary recovery projects. This provided further incentive for an ongoing development program. Since 1966, continuous flue gas injection has sustained the miscible flood and, being predominantly nitrogen, caused a constant increase in nitrogen content of the produced gas. The inlet gas to the processing plant currently contains from 30 to 45% nitrogen. The processing plant consists of three lean oil absorption trains for propane and heavier recovery. Residue gas from the processing plant, which is used for fuel, has declined in BTU content to below 800 BTU/SCF. All the fuel users were designed for 950-1000 BTU fuel. The fuel had to be "spiked" with a high ethane stream to maintain a 950 BTU fuel stream. This blending was satisfactory for several years, but variations in nitrogen content and momentary imbalances in this blending cause operational problems in the gas-engines, power boilers, and flue gas generators. Three alternatives were evaluated for solving the fuel problem: purchasing outside fuel, retrofitting existing equipment for low BTU fuel or building a nitrogen rejection facility. Nitrogen rejection was determined to be the preferred solution from an economic and reliability standpoint. The nitrogen rejection facility (NRF), built in 1983, handles 94 MMSCFD of the highest BTU (lowest N,) gas. This facility was designed to produce up to 38 MMSCFD of fuel gas while recovering 300,000 gal/day of NGL's.

The use of an intelligent ESP control unit (IESP) aids in remotely operated and "trouble" wells. Inputs from a number of end devices are used to determine the condition of the well bore and the equipment. Based on these inputs the mode of start-up or operation is "decided on" by the IESP. Control commands are then sent to the Variable Frequency Drive (VFD), switchboard controller, or back-pressure valve to achieve the desired mode of operation. This paper will discuss the concept and IESP design behind the initial project.

Petroleum Development Oman (PDO), working in close cooperation with several other companies, is developing and testing a remote, automatic, intelligent ESP system for Oman's challenging operations. This progress report describes the system concepts, expected benefits, and current status. PDO operates nearly 600 ESPs; this number is continuously growing. Many are located in very remote areas; many produce from sandy formations; many produce significant amounts of gas; most use fixed speed drives. These wells must be carefully started and operated to avoid damage from sand, inefficiency from gas, and safe and effective operation within the normal pump envelope. Currently, this is very labor intensive. Due to remote locations, it often results in excessive, hazardous desert driving, inefficient use of manpower, significant production deferment, and excessive operating costs. To optimize these wells, PDO is developing a system that includes downhole instrumentation to measure pump pressures and other key variables, a real-time sand production monitor, an automatic well-head control valve (for wells with fixed speed drives), and a full production automation (SCADA) system. The wells must be started and/or restarted slowly to avoid sand production problems or gas interference. Production must be ramped slowly enough to avoid these problems, but rapidly enough to avoid down-thrust or excessive motor heating. ESP Technicians are able to interact with the system from the field or corporate offices to optimize operational parameters and troubleshoot faults and shutdowns. Major benefits are expected to be up to 80% reduction in desert driving, significant improvements in production and equipment life, major reductions in deferment and ESP operating costs, and wider application of ESPs in preference to beam pumps and gas-lift. Initial field tests are underway in the Wafra Field in PDO. Implementation on more wells in PDO is anticipated when the field tests are successfully completed in early 2003.