The Austin chalk formation in Van field, Van Zandt County, Texas, USA, was identified as a candidate for infill drilling and recompletion. For the program to be economically successful, total well costs would have to be significantly reduced without compromising production performance. To achieve total systems cost reduction, a team of management, engineering and field personnel from both the operator and supplier was formed. The team's charter was to create a workover program that reduced the total operating cost by 25% without a detrimental effect on production. To identify and prioritize potential opportunities, the team employed a Structured Process Improvement exercise. Smaller task groups were formed, based on individual member expertise, to evaluate the feasibility and impact of each new technique. After a review of individual group recommendations, a revised workover process was implemented by the operator. Total systems cost reduction of 37% and replacement of 500,000 BOE reserves were realized in the first 90 of 150 planned wells.

For years engineers have known the value of elevated temperature cooling of internal combustion engines. As far back as 1916, Muir, Rushmore, Harrison, and others applied cooling systems to automobile engines which they called "controlled temperature," "steam cooling," and "evaporative cooling." While tests included operating at various controlled pressures to raise or lower the boiling point of the coolant, the control utilizing the natural law of boiling was found to be the most suitable.

Presents applications, design consideration, and economics of variable speed drives. Horsepower and torque requirements are shown for these applications.

The casing and tubing are subjected to have become increasingly more severe. Therefore, the manufacturer and user have had to find ways to perform non-destructive tests to measure the performance properties of these tubes. Wells are not only being drilled deeper but more areas of high pressure are being encountered. Secondary recovery projects quite often increase the working pressure under which the tubes operate. The stimulating processes for oil and gas wells, such as fracturing and acidizing, have brought about new demands on tubular goods.

The Petroleum Technology Transfer Council (PTTC) is a national organization established in 1993 to provide technology transfer to independent oil and gas operators. The organization is a funded partnership between DOE, state agencies and industry, which is headquartered in Houston with 10 regional offices serving all producing states. The PTTC Texas- Permian Basin was established in 1999 to assist the PTTC Texas RLO; the Bureau of Economic Geology. This paper will discuss the methodologies PTTC has utilized for transferring technology. The primary vehicles include workshops developed to address specific industry needs, case studies that represent proven technologies and industry's method of two-way beneficial sharing, and personal contacts via phone, fax, email, or websites. The PI

This paper summarizes the case history of the implementation of VeriTrax, a fully integrated chemical delivery and data management system. This is a computerized system that automates the processes involved in the provision of production chemicals, allowing for increased accuracy of chemical usage and tank levels for operators, and increased efficacy of chemical delivery and billing through a fully integrated SAP-based system. The Operator and Clariant Oil Services worked together to create VeriTrax, which optimized performance by eliminating manual input into both the Operator's and Clariant Oil Services" SAP systems. Complete details are given in the paper on the three components of VeriTrax: a global positioning system (GPS), a computer interface and a smart meter. When a delivery is made using VeriTrax, the GPS immediately identifies the well based on the location and the smart meter records the amount of product dispensed and sends this information into SAP.

The dynagraph animater is a device whereby we reproduce in miniature what happens at the pump as disclosed by the dynagraph. Guided by the dynagraph, we construct charts upon a cylindrical surface so that when viewed, while, rotating, through a fixed slot the motion of the rod system of the well and the pump action become animated - that is, they come to life and move, though on a reduced scale, quite as in the actual pumping well. Even blind men say, "I see" - meaning "I understand" - and so the animater was devised to aid the imagination in comprehending the complicated behavior of the enormous rod system and clarify our thinking on difficult problems.

Since 2001, over 1,450 patented Vortex tools have been sold into markets worldwide. On the surface, these Vortex tools set up a stable spiraling flow that keeps liquids from dropping out, prevents freezing, reduces pressures and mitigates paraffin build-up. Downhole, Vortex tools enable wells to flow below the critical rate as well as lowering the bottom hole pressure and reducing surfactant use by up to 50%. With no moving parts, all Vortex tools are virtually maintenance free. In 2009, a Texas independent producer began installing Vortex tools on gathering lines to recover substantially more natural gas liquids (NGLs) than they were previously getting with pigging and/or drip systems, all with marginal
affect to the value of the gas (7-12 BTU). After collecting 15 months worth of comparable data (lines with Vortex to lines without Vortex), the data concluded the following: Over 1.2 million gallons of additional NGLs were recovered from three gathering lines with the Vortex tools in a single year, translating to over $2 million in additional revenues. An average well line with Vortex paid for itself in less than 60 days (including the cost of the Vortex tool and associated tanks and installation). There were also additional "non-revenue" benefits like reduced
pigging, lower methanol use, reduced hydrate formation and zero line freeze-ups on gathering lines with Vortex. These "non-revenue" benefits (and more) have been confirmed by numerous university studies, Department of Energy (DoE) testing, case studies and various White Papers, including SPE 84136.

Today the oil and gas industry is on the front end of a serious labor shortage, with an impending loss of senior expertise to retirement. University programs in petroleum engineering and the geosciences have declined in enrollment as a result of reduced hiring by oil and gas companies. The industry has a poor public relations image that further alienates young talent. Education will play a key role in solving the serious labor shortage that already affects domestic oil and gas operations. Short-term, companies will need to provide incentives to keep talented professionals working longer. Long-term solutions may include outreach programs to high school and college students; industry's role may include summer jobs and intern programs to encourage students to pursue oil and gas careers. Ultimately, industry, government and academia will need to work together to make meaningful headway in assuring a viable workforce for the domestic oil and gas industry.

Under balanced horizontal drilling (ubhd

The use of wash tanks for emulsion treating has been employed in the oil field for many years, even though direct fired vessels have been the most popular treating device in recent times. With the present concern for energy conservation, and with the ever-increasing value of residue gas, cold treating of emulsion with a wash tank may be the most attractive method in many applications. Regular production stock tanks have been adequately utilized as wash tanks in "stripper" operations where the quantity of emulsion and producing GOR is small. In these simplified installations, the produced fluid is piped directly to the tank, and oil is spilled through an equalizing line to another stock tank. A water leg may be used to control the water wash level or, if water production is minimal, the water may be simply contained in the tank and trucked as necessary. This type installation may suffice in marginal operations; however, where larger volumes of emulsion are to be handled, significantly more design and installation work is necessary to provide an efficient treating device at the least possible installation cost.

In any water flood project the operator may take one of two routes regarding water analyses made at the start of the project and during its life. The other, a more desirable route, is to have pertinent analyses made at the beginning and periodically during the life of the project. This paper outlines some of the problems that can occur as the result of changes in injection water. Corrosion of equipment and piping, plugging of the producing sand, scale formations, and the role of bacteria are discussed.

The paper will attempt to present the law of Texas and adjoining states relating to the use and ownership of water as such law concerns and should be of interest to the oil and gas lease owner and operator. The paper will discuss such subjects as ownership of the fresh water and salt water under grant, reservation, lease or permit; right of user of the surface owner, the mineral owner, and the oil and gas lessee; regulation by the State and its governmental agencies; and responsibility for wrongful use, loss, or pollution.

Many ESP failure modes result in the ingress of water into the motor resulting ultimately in motor electrical failure. Knowing that the isolation of the motor from well fluid has been compromised. Would allow the option of pulling the unit before electrical failure, significantly reducing the cost of repair. Various methods have been used to monitor insulation resistance to determine the electrical condition of the motor and cable, however, these methods are relatively expensive, and do not provide an indication until the insulation system has already been affected. This paper describes a method of detecting the presence of free water at the bottom of submersible motors. Fifteen such units are installed and functioning as expected, however, the benefit is yet to be demonstrated.

Among the peculiarities of producing an oil well which is involved in a secondary recovery project by water flooding, it is probably outstanding that the performance history of such a well can be expected to be in exact reverse order of that expected from a normal primary producing well. At the outset of a water flood project, the normal producing well is a marginal producer or "stripper," possibly making only one or two barrels daily. As the injection begins to yield results, old production equipment, such as the central power and gas lift equipment, is retired in favor of an individual pumping unit capable of handling the increasing volume and load. This volume and load continue to increase throughout the life of the water flood producer, even though the percentage of oil eventually starts to decrease as water production starts. Finally, as the high lifting cost per barrel of oil becomes prohibitive due to the small amount of oil being produced, the rods and pump are removed and the well is allowed to flow for the remainder of the project. Thus, the life of a primary producing well has been traced, but in reverse order.

The correct application of equipment on waterflood projects has become difficult and confusing to the waterflood operator during the past several years due to the multitude of equipment available which will perform the same function. This paper is being presented to pass on information that might help eliminate a portion of this confusion. It is based on observations and past experience of the writer.

Before discussing the various types of problems which arise when water is injected during waterflood operations, it is advisable to define the term "satisfactory intake rate". This is not as easy to define as it might seem, and a clear definition which will fit all cases is not possible. Early in a waterflood operation (first few months), the water injection rate at a given injection well may be considered satisfactory if the rate is two or three times greater than the injection rate at the same well a year later, even though in each case the pressure applied at the well head is exactly the same.

This paper presents the application of an organically crosslinked polymer system (OCP), a system widely used in the oil industry for water shutoff applications. The OCP system is based on a copolymer of acrylamide and t-butyl acrylate (PAtBA) crosslinked with polyethyleneimine (PEI). To date, more than 300 jobs have been performed worldwide and at least about 100 jobs have been done in Mexico with this system to address conformance problems such as: water coning/cresting, high-permeability streaks, gravel pack isolation, fracture shutoff, and casing leak repair. An overview of case histories which utilized OCP in various regions of Mexico is presented for a wide variety of applications. Particularly, a case history of an offshore well treated with the OCP is presented. A direct comparison of the application of the OCP with conventional cement squeeze treatment is presented to illustrate the advantage of having a deep matrix penetration for a more efficient water shutoff. In addition, data presented in this paper indicates the development of a retarder that allows the upper placement temperature of the OCP system to be raised to at least 350_F. The upper placement temperature of the system originally was ~260_F.

The significance and importance of water to the Oil and Gas Industry cannot be overstated. While water is often an unwanted by-product of production, water is utilized in many production scenarios and is often times the primary driver for the production of oil. Water, by its inherent nature, will dissolve and carry many impurities within it. These impurities will remain in equilibrium with each other until acted upon by some outside force. These impurities can result in accelerated corrosion, mineral scale depositions, stress corrosion cracking of metals, plugging problems and erosion/corrosion of metallic equipment. It is vital to gain an understanding of the dissolved and suspended constituents of produced, or injected, water and to identify relevant changes in these compositions. This paper will discuss the importance of an accurate water analysis and will discuss the practical uses of this information.

Waterflooding in the Caprock Queen Field began with a pilot waterflood initiated in 1956. Today, essentially the entire field is under waterflood. There are 13 different projects in operation; eleven are units while two are of the cooperative type. All P3 projects have utilized 80- acre five-spot patterns. This case history is presented in order to depict the general performance of 13 successful Queen Sand waterfloods, and should be helpful in predicting the performance of other waterfloods that may be initiated in similar reservoirs. In many cases the engineer, is forced to use experience factors or "rules of thumb" in order to predict the performance of a proposed waterflood. When adequate reservoir, data is available he should, of course, make use of it in predicting performance. However, even after making calculations and the corresponding predictions, the engineer should attempt to compare his predictions with actual performance of other floods, either in operation or depleted, which are similar to the flood he is proposing. Quite often there are floods in the same field or in the same formation in a nearby field that are comparable to the proposed flood. A review of the performance of similar floods can be helpful, not only in designing the injection system and selecting a pattern, but also in making a reasonable predication of the performance that can be expected. The data used in preparing this case history was taken from reports published by the New Mexico Oil and Gas Engineering Committee.

This paper reviews the history of pilot waterflood projects in the Panhandle. It discusses specific floods and results obtained from them.

A waterflood pattern realignment project in the Grayburg / San Andres McElroy Field is improving the waterflood performance. This paper presents a case history of a 640-acre [259 ha] section of the field that was realigned in 1988. Irregular and widely spaced patterns were developed into smaller and more uniform patterns. The results of the realignment are proving the economic viability of realignment work at McElroy and are improving reservoir characterization.

Surveillance, in order for it to be effective, should be implemented through an organization with adequate staffing and technology. Engineering and field operations organizations should be complementary, providing for specific lines of communications, and yet at the same time encouraging informal personal exchanges between both groups. Surveillance of a waterflood project requires constant cooperation between the two groups in order to collect, document, and analyze an immense quantity of data, and carry out an efficient operation.

The Grayburg formation in the Johnson field, Ector County, Texas, is a more complex reservoir than originally believed. Poor response from waterflooding the J. L. Johnson "AB" lease with 40-acre five-spots led to development with ZO-acre line-drive patterns. This caused a substantial production increase. Infill drilling has lead to the discovery of random, anhydrite-filled sections which act as barriers to flow. They are probably interconnected and may be the cause of poor response to injection on wide spacing. Anhydrite barriers may exist both in other parts of the Johnson field and in surrounding fields. These barriers could play an important role in determining how other waterfloods are designed.

Electronic equipment is available for installation on electric motor driven beam pumping units which provides load and displacement data for a complete well analysis including rod stress, gearbox torque and downhole pump card calculations. The electronic equipment also monitors the load and displacement and shuts the well down for a predetermined amount of time when a pumped-off condition occurs and also shuts the well down and sets an alarm when a rod part is detected. When well data is needed for analysis the load and displacement data can be plotted on a dynamometer and at the same time the load and displacement data is recorded on an electronic memory card for replay into a computer. The electronic memory card records one full cycle of the pumping unit in equal time increments for use in gearbox torque and downhole pump card calculations.