Typically, channels or streaks of high permeability develop after a period of time in CO2 injection programs. To help prevent injected CO and water from bypassing Recoverable oil polymer is injected which alters permeability to permit injected CO2 and water to contact previously bypassed oil-bearing formation. With the development of the laboratory apparatus described in this paper, significant improvements have been made in analyzing and designing polymer injection strategies to improve conformance control. The apparatus consists of a parallel series of cores of varying permeability to simulate variations in formation permeability. These cores are subjected to sequential injection of CO2 and water, followed by polymer injection. Effects of polymer injection on formation permeability are then evaluated. Results of studies conducted using this laboratory apparatus have led to findings regarding: 1. Selection of a nonionic organic crosslinked polyacrylamide polymer which is stable in the low pH environment of supercritical CO2. 2. Determination of an optimum treatment size to preferentially alter permeability to improve conformance control. 3. Long term effects of the CO2 environment on stability of injected polymer.

The economically successful exploitation of oil and gas resources has become more and more difficult to achieve as the quality of the reservoirs available for exploration have declined. In the last decade much of the activity on-shore in the lower 48 states has concentrated on previously by-passed lower quality reservoirs and in intensive in-field drilling programs in mature fields. Tertiary recovery projects have been emphasized but typically do not compete with well conceived primary production projects. Under these marginal economic conditions, the implementation of optimum completion practices will often make the difference between economic success and failure. The purpose of this paper is first to relate several well histories to demonstrate some important observations about the influence of completion parameters on well productivity. Secondly, it will demonstrate the role of laboratory studies in optimizing completion practices. Finally, it will emphasize the need to fully understand the necessity of using laboratory tests, and ensuring that the tests employed can provide field implementable answers and not just laboratory data from routine tests.

The economically successful exploitation of oil and gas resources has become more and more difficult to achieve as the quality of the reservoirs available for exploration have declined. In the last decade much of the activity on-shore in the lower 48 states has concentrated on previously by-passed lower quality reservoirs and in intensive in-field drilling programs in mature fields. Tertiary recovery projects have been emphasized but typically do not compete with well conceived primary production projects. Under these marginal economic conditions, the implementation of optimum completion practices will often make the difference between economic success and failure. The purpose of this paper is first to relate several well histories to demonstrate some important observations about the influence of completion parameters on well productivity. Secondly, it will demonstrate the role of laboratory studies in optimizing completion practices. Finally, it will emphasize the need to fully understand the necessity of using laboratory tests, and ensuring that the tests employed can provide field implementable answers and not just laboratory data from routine tests.

This paper reviews the features and laboratory tests for a unique downhole gas-solids-liquid separator that has been designed. The objective of this project was to develop a gas separator that would perform efficiently at high fluid flow rates and could be also used in combination with a solids separator. The device attaches to the inlet of progressing cavity and beam pumps. With electrical submersible pumps a shroud is used. Scale-model tests were used to evaluate the design at high fluid flow rates.

A discussion of the LACT, as viewed by the pipeliner is presented. Requirements of measurement, tolerance of performance and general examination of this new facility is included.

The drop in oil prices has required everyone to reevaluate their operations to reduce operating costs and improve profit. One potential way to maximize a lease's profit is to ensure that a LACT Unit is properly built, maintained, operated, and proved. ARC0 Oil and Gas Company (AOGC) recently revised their LACT Unit Design and Operation Standards to address these issues. This paper briefly discusses several sections of those new standards which have a significant impact on measurement quality.

Lease Automatic Custody Transfer (LACT) is the name given to the systems which automatically perform the functions of measuring and recording of temperature compensated oil quantity; sampling for subsequent determination of quality; and the running of the oil from the lease into the pipeline in accordance with preset schedules on an unattended basis. Automatic monitoring of oil quality with shut-in of unit on sensing of unmerchantable oil is used in conjunction with LACT. There are two basic types of LACT metering in use in the industry today. These units are (A) positive volume dump meters and (B) positive displacement meters. Each of these units is designed to perform the functions described above but each utilizes different methods. A third unit (C) is a special adaptation of (A) for use on small volumes.

Options for improving productivity in older wells are re-stimulating the well or adding laterals extending past the original wellbore. A new technique achieves both in limestone formations. This technique creates pre-stimulated "tunnels" that bypass near-wellbore damage to make contact with newly exposed reservoir rock. This technology relies on hydrochloric acid's ability to dissolve limestone along with a coiled tubing bottomhole assembly made to kick over toward the formation. A nozzle then jets acid at the formation creating tunnels extending from the wellbore. The technique works in all open-hole wells drilled in limestone and can be used to make multiple laterals in new or old wells. This procedure was recently used in the United States for the first time. Three tunnels were created in an Oklahoma stripper well. This paper describes the tool and design including an operational timeline; lessons learned during the Oklahoma operation, pre- and post-job production information, and a cost/benefit analysis for the treatment.

This paper describes the use of associative polymer technology (APT) to achieve fluid diversion during an acid stimulation treatment. APT involves the use of a very low viscosity aqueous polymer solution. It adsorbs immediately onto the formation surface and significantly reduces the ability of subsequent aqueous fluids to flow into high permeability portions of the rock. The first stage containing the APT predominately will enter the most permeable area, diverting following acid stage(s) to other less permeable sections of the rock. APT has little or no effect on the flow of subsequent hydrocarbon production. Parallel flow study data using water saturated and oil saturated cores will be presented which shows the ability of APT to divert acid, in both sandstone and carbonate cores. In addition, case histories will be presenting showing the effectiveness of APT.

For many years, bull head systems to reduce water production have received a great deal of attention from the oil- and gas-production industry. Previous papers have discussed the laboratory development of a new bullhead system based on a hydrophobically modified polymer. This paper will outline the field implementation of this system and will describe some of the successes (and failures) of the system. Even though bull head systems do not seal off water zones and thus do not have the capability to completely stop water production, it will be demonstrated that these treatments can be extremely economically attractive. While field

Water production in gas wells can be a huge problem, in many cases causing premature well abandonment. Numerous techniques are used in attempts to allow continued production, including the use of foams and plunger systems. However, these techniques require continuous injection of chemicals and/or maintenance of equipment. Stopping, or slowing down, the water is another approach to the problem. This paper will discuss a bullhead polymer system which reduces the permeability to water much more than to gas. The system does not require zonal isolation of the water producing zone, making for much simpler job design and execution than standard crosslinked gel treatments. The paper will discuss the polymer chemistry, laboratory test data, details on job design and execution, as well as case histories.

This paper covers the newer (since 1959) developments in equipment for rod pumping in multiple completed wells. It also reviews some of the trouble with the earlier equipment and the corrective measures that have been taken.

You could hardly have picked a more important topic for a meeting of production people. Oil lifting is not only the ultimate aim of a great deal of out work in the production end of the petroleum industry, but it is also a part of the business in which some of the most important improvements and changes are being made. In oil lifting, you have to keep running these days just to keep from losing ground . . . Fortunately, however, there has been a growing awareness throughout our country that learning can be-and should be-a lifetime proposition. You can see this awareness in industry, and you can see it in the universities. In industry, training programs are flourishing as never. before-training covering every pertinent subject from fast reading to slow driving, from the fundamentals of safety to the fundamentals of supervision. In the colleges, extension courses and short courses and night classes have thrown open the gates of knowledge to all who would enter.

To date, there have been two major automation projects in the Fullerton Clearfork Unit. The first was completed in 1956 and included 57 wells. It consisted of complete automation from the wellhead to the storage tanks with no custody transfer facilities. This, being a pioneer installation, required some changes and revisions before satisfactory operation was obtained; however, once completed it have operated satisfactory. The second project, including 51 wells, was completed in 1958. The essential difference between these two projects is that the first was designed to handle intermittent flowing wells, while the second was designed to handle pumping water flood production and includes "LACT" facilities. This paper is concerned, primarily, with a discussion of these automation projects and the types of equipment used. It discusses briefly the operational and economic criteria for the application of automation.

In everyday language the term "Custody Transfer" means simply a "sale", and the Lease Automatic Custody Transfer may be defined as the unattended sale of oil by the producer from the lease tanks to the pipe line. Under this method, all the operations of gauging and thiefing the tank, or determining the BS&W content, the temperature and the gravity of oil, and finally of placing the tank on the line, normally done manually, are being performed automatically.

The fundamental criteria for a good electrical system is delivery of electrical energy at a satisfactory level. How to allocate voltage drop and benefits from proper application of capacitors is explained. Optimum voltage spread results in minimum total cost.

Oil and condensate producers can significantly increase their revenue by using skid-mounted, portable lease-type packaged gasoline plants to remove hydrocarbon liquids from wet lease gas streams. The 500-3,000 MCFD capacity units are easily maintained and operated by lease pumpers since only conventional oil field equipment is involved. Recovery has varied from 33.5 bbls. Per MMCF on high pressure separator gas streams, to 144.5 bbls. Per MMCF on treater gas streams. This article describes typical application and operation of the lease type plants.

Gas engines can be leased for a fixed monthly fee, including complete maintenance. In many cases this leasing service is the most economical method of lifting crude oil.

A growing majority of oil and gas fields in North America are mature or heavily depleted proposing many challenges for economic production. Low reservoir pressures, along with liquid loading, have become some of the main hurdles to overcome when attempting to economically produce natural gas. Deliquifying wells using artificial lift has become a prominent method used to tackle these issues. This paper discusses the challenges faced in the Oil and Gas industry with an eye to deliquifying mature or depleted reservoirs. It describes the pros and cons of the pump jack and the LeBro pump actuator currently being tested; it compares the cost of installing a pump jack vs. a LeBro pump actuator; and it also talks about testing done on horizontal Coal Bed Methane wells, and future design and implementation on deep well application (~12,500').

In a few short years the delivery of chemical products has been one of the fastest growing technologies in the oil and gas industries. From acid sticks, corrosion inhibitors, and specialty soap sticks, an evolution of several generations of chemical delivery has evolved into near total automation that has proven to be safe, efficient, and cost effective. From dismantling equipment and using laundry detergents to automated chemical stick launchers, the new generation dispenses chemicals according to the gas wells needs and predetermined chemical protocol for individual gas wells. Oil and Gas producers have available to them the future of solid chemical launchers and automation for increased production and reduction of costly man hours.

Well tests are crucial to managing rod pumped wells, and operators struggle to get tests as frequently as they desire. A method has been developed using the down hole pump card generated by a Rod Pump Controller that has proven to be accurate and reliable. The method will be explained and data will be presented from field tests showing actual well tests compared to the well test from the Rod Pump Controller.

The use of curable resin pre-coated proppants was often applied in the Permian Basin area to control proppant flowback. However, these pre-coated proppant materials continued to allow propopant to produce back, especially during production surges because they did not provide sufficient consolidation strength to handle high drawdown. Since early 2005, a low-temperature curable liquid resin system was selected to treat the proppant on-the-fly mainly during the tail-in stages in most of 1,500 hydraulic fracturing treatments. This paper highlights how the proppant back-production problems were successfully overcome through the application of this curable resin system. Detailed descriptions of the treatments, challenges, and lessons learned during the course of these fracturing treatments are presented.

The deregulation of the Texas electric utilities has created many opportunities and challenges for oil and gas producers. Questions continue to be asked regarding how oil & gas producers will purchase power. With the enactment of 1999's Senate Bill 7, electricity buyers are beginning to find out the "devil is truly in the details". Challenges when purchasing electric power include reviewing contract terms and conditions; determining (deciding on (or selecting)) the most suitable contract duration; analyzing complicated pricing proposals and their links to gas markets; determining the optimum pricing options. The buyer's challenges continue with billing and collection issues such as ancillary charges, profiling, bill formatting and delivery options, and procedures for contesting billings. As Retail Electric Providers fight to establish market share, more creative and innovative pricing options will become available. Minimizing power costs will require producers to keep both eyes open: One eye on the power markets to make the best power purchases they can, and the other eye on their operations to optimize power use.

Companies with large geographically dispersed networks, such as those in the oil and gas industry, can select one technology, one source, one vendor, to collect, retrieve, report data, and to assess the health of the network. Sometimes, this type of approach makes sense. However, other times integrating other types of technologies offer significant benefits that can easily and more cost-effectively be incorporated into one cohesive network. In fact, the days of building large, unmanageable networks are behind us. Building large, elaborate radio networks is a way a company might demonstrate its vast expertise and deep knowledge base. However, there are options that allow us to consider better manageability, expandability, cost and speed.

The 2.8 Billion Barrel (Original Oil in Place) SACROC Unit is located in Scurry County, Texas and produces from the Pennsylvanian-aged Cisco and Canyon Formations of the Kelly-Snyder and Diamond M Fields. This Unit has had a colorful history, with discovery shortly after World War 11, nearly half a century of waterflooding, three decades of tertiary development, and a wide variety of operators and philosophies. Since the time of SACROC's early CO, efforts, local experience and industry practices have contributed greatly to our knowledge of CO, flooding in general. Today, Kinder Morgan CO, Co., L.P. (KMCO,) is CO, flooding an area in the central portion of the Unit (using new techniques and philosophies) with great success. Unit production is now at a nineyear high, with average monthly production exceeding 13,000 BOPD. Tertiary recovery efforts are very expensive and require a great deal of reservoir understanding to reduce risk and increase efficiency. So, KMCO, has initiated a dual-pronged approach to the continued development of SACROC Unit, with flooding efforts currently focused on "less risky" areas, and with more intense geologic study focused on understanding the more complex, higher risk, and greater potential areas. However, even in the low risk areas this reservoir is extremely complex and data is sometimes scarce, misleading, of low quality, or ambiguous. Relatively few modern logs exist, and unique situations can cause confusion about log responses. Correlations are difficult in certain areas due to complex geometries associated with mound buildups, erosional contacts, and local depositional geometry. Because the reservoir's internal architecture is so complex, strange fluid flow responses sometimes occur in areas that appear rather simple at first glance. That said, the Unit can still be divided into northern, central, and south-western regions for general comparisons. A thick, north-south trending platform, with karst features that increase in intensity to the north and higher in the section, dominates the northern area. The central region is a broad, gently arching plain broken by steep-sided pinnacles, gentler mounds, intermittent sinuous lows, and localized depressions. The southwestern area is the most structurally complex region of the Unit, with a series of faults and channels that contribute to small, isolated compartments. Success at SACROC can be credited to the geology and hydrodynamics of the reservoir, the technical feasiblity of tertiary recovery with CO,, and the efforts of a multi-disciplinary team providing input from field, reservoir, and corporate levels.