Incomplete pump fillage is often associated erroneously with a "pumped-off well", meaning that the pump displacement exceeds the production capacity of the reservoir, ignoring the fact that there are two other causes of partial liquid fillage: gas interference and the presence of a flow restriction or excessive pressure drop at the pump intake. The result of a misdiagnosis is to incorrectly set the mode of operation of pump-off controllers, variable speed drives or timers thereby loosing significant amounts of production. This paper describes the three causes of incomplete pump fillage, presents several sets of field data for the various cases, discusses how to combine dynamometer and fluid level records to correctly identify the source of the problem and presents recommendations for possible solutions.

The economic benefits to be obtained from use of a through-tubing bridge plug have long been known by the petroleum industry. However, early attempts to produce a reliable through-tubing bridge plug for casing were not successful. Sustained engineering effort was begun by Schlumberger in the middle 60's to devise a through-tubing bridge plug that would give consistent plugging results. Many problems that had not been previously recognized were highlighted. This engineering effort produced the "Plus Plug", a new concept in through-tubing bridge plugs, which was introduced to the field in the late 60"s. Actual usage in the field has brought additional problems into focus. Additional engineering effort is being expended to improve the plus plug so that it will be capable of a wider range of usage.

Because of the complexities of pumping dense phase C02, it is recommended that one supplier provide all components. These should be completely skid mounted with pump, driver and accessories,- valves, headers and controls all preassembled, wired and tested.

Sand problems can cost a company valuable time, money, and resources. Various methods have been used to reduce sand problems experienced in rod pump operations. This presentation will propose an alternative solution utilizing pump screens and tubing screens to handle the sand problem and increase production and profit capability. Illustrations will be examined, which explain how pump and tubing screens function, and case studies will be reviewed that discuss the benefits and limitations of the screens.

Sand problems can cost a company valuable time, money, and resources. Various methods have been used to reduce sand problems experienced in rod pump operations. This paper will present an alternative solution utilizing Pump Screens and Tubing Screens to handle the sand problem and increase production and profit capability. Illustrations will be examined which explain how the Pump and Tubing Screens function, and case studies will be reviewed that discuss the benefits and limitations of the screens.

Sand problems can cost a company valuable time, money, and resources. Various methods have been used to reduce
sand problems experienced in rod pump operations. This presentation will propose an alternative solution utilizing pump
screens and tubing screens to handle the sand problem and increase production and profit capability. Illustrations will be
examined, which explain how pump and tubing screens function, and case studies will be reviewed that discuss the
benefits and limitations of the screens.

Hydrochloric acid has been used for more than 40 years to improve production in oil and gas wells. Many techniques have been used to improve results of hydrochloric-acid treatments. One of the most important advances has been recognition that fracturing occurred during the majority of acidizing treatments. This enables the use of fracturing principles to increase live acid penetration. Unfortunately, actual results did not correlate with predicted results. This prompted the use of many techniques to improve results. Some of these are listed below. 1. Acid retardation 2. Increased acid concentration 3. Increased injection rates 4. Increased fracture width to decrease area-to- volume ratio 5. Improved matrix leakoff control 6. Increased pad volumes 7. Improved computer programs. All of these approaches had the purpose of increasing live acid penetration, and thus improving conductivity to the wellbore. Although each action helped either separately or when used in various combination, still a large gap remained between predicted and actual results. The problem has been that the work was based on the assumption that leak off was due to matrix permeability.

The necessity of developing cleaner fluids for the purpose of well stimulation has been the topic of current discussion among oil company and service company personnel alike. In fracturing, the incorporation of specific quantities and types of gelling agents and fluid-loss additives has been considered only as means by which to obtain effective viscosities for proppant transport, fracture width development, and efficiency via low leak-off of fluid away from the direction of fracture penetration. Since it has been established by several investigators19 2 that fluid-loss additives and natural agent gelling compounds may contribute significantly to formation damage, a need for a clean fluid encompassing the properties of effective viscosity, low fluid-loss, efficiency and comparable economics is evident. This will be shown in tabular and application history forms. One solution to the problem is to utilize a highly efficient ultra-low residue, chemically substituted, natural polymer at low concentrations, and employ the principle of cross-linking to allow actual link-up of the molecules to provide several folds of viscosity increase over that obtainable by the low concentration base gel; and via the process of interlocking or connecting molecules of guar polymer, create an excellent fluid-loss control mechanism such that little or no additional fluid-loss additive is required?, 4 This system may be batch-mixed into frac tanks unlike the predecessor high concentration cross-linked gels. The guar used is of a relatively new type, being a highly refined (0.5% residue) chemically substituted hydroxyalkyl-type. This product's molecular structure is compared to the conventionally used guar molecule in Fig. 1. When cross-linked at a concentration of 15 lb/1000 gal. aqueous phased fluid, the individual hydroxyalkyl molecule, as shown in Fig. 2, is cross-linked by bonding, as shown in Fig. 33. It may be stated that the use of the abovementioned hydroxyalkyl polymer in the cross-linked state at relatively low concentrations compared to conventional oil or water-based fracturing systems is a comparably efficient or more efficient, more effective fracturing system. The evidence for showing the low-residue hydroxyalkyl cross-linked guar system to be comparable, or better, than conventionally designed gels containing between 20 lb and 60 lb gelling agent in addition to 20-40 lb of fluid-loss control material is borne out by viscosity, fluid loss, friction loss, fluid efficiency, and cost evaluation testing. See Table 1.

Acrolein (2-propenal) is a potent biocide and sulfide scavenger which has been used to mitigate bacterial and iron sulfide problems in secondary oilfield recovery systems. The effectiveness of acrolein is due to its _,_-conjugated double bond which reacts with sulfhydryl and amine groups on bacterial proteins as well as irreversibly reacting with sulfide ions in hydrogen sulfide (H2S) and iron sulfide. This paper discusses the applications of acrolein in water injection systems to control bacteria, H2S, and iron sulfide scale problems impacting water clarity, injection flowline integrity, and injection well performance. Data are presented on three case studies which describe 1) the reduction in injection well failures due to acid producing bacteria, 2) remediation of iron sulfide formation face damage in injection wells via squeeze applications, and 3) remediation of iron sulfide fouled injection wells via a novel topside batch treatment program.

In recent times, a tremendous amount of effort has gone into the development on nonaqueous fracturing fluids. These fluids, usually alcohol or high-gravity hydrocarbons, which may contain propane, carbon dioxide or nitrogen, have been utilized in the stimulation of many formations. The above systems, while normally being successful, have some shortcomings. Generally the fluids are expensive and many require specialized equipment. With the introduction of a new fracturing fluid based on mixtures of alcohol and water, a lower cost alternative is now available. The alcohol-water systems are particually applicable in low-porosity, low-permeability gas reservoirs. Laboratory tests with formation cores show that the effective permeability to gas following injection of alcohol solutions is much more rapid than when water is the injected fluid. These fluids, which can contain from 20 to 40% methanol, also aid in protecting water-sensitive formations against clay swelling and migration. In addition, the presence of alcohol markedly reduced the surface tension of the fluid. These advantages permit rapid production fo the fracturing fluid from the formation. Many field tests have shown that rapid cleanup is obtained with this system. This paper presents a description of the fluid system, various viscosities that may be obtained, including crosslinked or delayed gels, as well as laboratory field results.

As the energy situation becomes more critical and more domestic oil is desired, new methods of stimulation are needed. Conventional methods generally have not been successful in treating thick or massive pay sections whether in cased or open hole. This has been true for squeeze cementing as well as fracturing and acidizing treatments. In the Levelland-Sundown areas of West Texas, most of the producing formations are thick, fractured limestones of varying porosity and permeability. The problem here has been to treat the low-permeability or tight zones as well as the more permeable zones. Many diversion methods have been tried without success. These have included straddle packers, ball sealers, and the suspended-solids type of blocking agents. While all of these may force the stimulation fluid to enter the tight zone, the fluid generally will penetrate only a short distance before seeking a fracture back into the more permeable zones. As a result, fluids from later stimulation treatments have undoubtedly been injected back into the originally treated zone time after time. The same is probably true of cement when attempting to squeeze-off undesired zones such as water-producing zones or channeled zones in injection wells. A new method of diversion has been employed with a high degree of success in this area during the last two years. The method involves the use of two fluids, one "tagged" with a radioactive material and another "untagged" fluid. The "tagged" fluid normally is pumped down the annulus while the untagged fluid is pumped simultaneously down the tubing. A detection tool, run on a wire line, is used to monitor the interface between the two fluids. The interface indicates the place of entry of the two fluids into a zone. The location of the interface is controlled by means of pump rate. It can be moved up or down by varying the pump rate down the tubing or annulus or both. The interface method allows control of stimulation fluids not only at the wellbore but out in the formation as well. Figure 1 illustrates one type of interface treatment. In this example, the problem is to acidize a low-permeability zone below a zone of higher permeability. In this case radioactive water _ is pumped down the annulus while acid is pumped simultaneously down the tubing. The radioactivity detector is located in the tubing and the interface is controlled at the top of the low-permeability zone. Most acid inhibitors are capable of protecting the wire line and detection tool from damage by the acid. However, in extremely deep or hot wells, special inhibition requirements may be required by the wireline company. In Fig. 2, the problem is exactly the opposite of that in Fig. 1 and is the problem usually encountered in the Levelland-Sundown area. Here the zone has

Since the early days of oil production, operators have been plagued by emulsified oil. It has been estimated that about 70 per cent of all crude oil is produced in the emulsified form. Before this oil can be transported and refined the emulsified water must be removed. In the early days of the industry, pipe lines would accept oil containing upwards of 5 percent water, while today they will accept only 1 per cent water of basic sediment. Many methods of removing the water and emulsion from this production have been tried with varying degrees of success. In the early days of flush production the "cut oil" or "rolly oil" was flowed or pumped into large earthen pits where it was subjected to treatment by the sun. This slow process produced a top layer of dry or "clean" oil which was decanted periodically and sold. Most of the light fractions were lost in the process but little thought was given to the loss as kerosene was the more important fraction and oil was being produced as fast as it could be dehydrated and sold. Later, some improvements were made by the use of hay tank filters. Centrifuges were tried at some refineries and electrical demulsification was used in the oil fields as well as in refineries. When the operators discovered that lye, washing soda, and strong soap powders such as the old "Gold Dust" rosin soap would break these emulsions, the use of chemicals in oil fields began.

Are the new flaring regulations creating more headaches for you?

This paper covers the use of foam fracturing in the Ft. Worth Basin. It will discuss the design parameters and economic considerations in foam treatments. Finally, case histories will show results of production.

ARCO Oil and Gas Company has drilled two horizontal drainhole wells in the Empire Abo Unit. A horizontal drainhole well is one in which the wellbore is turned from vertical to horizontal in a short radius and the horizontal hole is then drilled out some distance into the formation. These wells were drilled to evaluate the mechanical feasibility of the drilling process and to examine the effect producing through the drainholes would have on the well's tendencies to form gas cones. Although several problems were encountered while drilling the drainholes, the drilling technique used does seem to be mechanically sound. The wells have not been on production long enough to fully evaluate their gas coning performance as compared to conventionally completed wells. This paper will briefly examine the gas coning problem in the Empire Abo Unit, discuss some of the techniques used to limit gas coning in the Unit, and review ARCO's experience with horizontal drainholes.

Historically, gas recovery was not considered a profitable proposition for producers in the Permian Basin. Today's commodity gas pricing makes it a viable revenue generator with a 10:1 recovery payback. Safety and environmental incident prevention, lost profit potential, responsibility to shareholders, and the economics and feasibility of thermal imaging create a convincing case for investing in infrared thermography. Pioneer Natural Resources operates 5600 producing wells and 1617 tank storage batteries, with more than 2,000 miles of flow and transmission line in the Permian asset. In 2007 the company invested in a gas leak detection camera and a thermographer. The economics, safety and environmental benefits proved so compelling that a second camera and thermographer were added in 2008.

The accumulation of paraffin deposits in pumping wells and flow lines presents a production and transportation
problem that is very costly to the oil industry. This problem has been attacked in many ways and, until a few years ago, the removal of such deposits was accomplished by mechanical means only. These usually involved lost time, extra labor, and special tools, all of which were expensive to the operator. Because
of the high cost of mechanical methods, it was found that, in many cases, the use of chemical solvents
was a more economical way to remove paraffin deposits. Such solvents, when properly applied, removed
paraffin deposits from the well and flow line, with far less expense to the operator.

One of the factors influencing the potential applicability of a tertiary recovery program to a specific reservoir is the amount and distribution of oil remaining in the reservoir. Experience has demonstrated that predictions for determining the yet-to-be-recovered oil saturation are frequently optimistic. More positive means for accurately assessing the reservoir oil saturation are needed. Two procedures have recently been used in Amoco's operations in an effort to better define reservoir oil saturation prior to the planning of a tertiary recovery program. These procedures were the use of: 1) Esso's pressure core barrel, and 2) a log-inject-log technique. Pressure cores were obtained in watered-out locations in three different reservoirs. One of the reservoirs was very loosely consolidated, highly permeable sandstone, and the oil saturations found in the cores were considered to be lower than actually existed in the reservoir. Possible factors contributing to the low oil saturations are discussed. Pressure cores from the other reservoirs, both dense carbonates, contained oil saturations in the range expected on the basis of laboratory flow tests on native-state cores.

Two predominant methods, millipore filtration and turbidity, have been used in the past to measure the efficiency of filters. These methods are useful for empirical measurements of filtration but do nothing to quantify the various sizes of interest. The introduction of the Coulter Counter to industrial application has presented a new method for monitoring filter performance. Now, the efficiency of the filter can be determined at any size from 0.4 to 800 microns. This paper illustrates the use of the Coulter Counter in the development of a new filter design. The testing involved laboratory testing of the pilot filter, on site location of the pilot filter, and final onsite testing of a full size vessel.

The Thermal Decay Time (TDT) log is used to detect hydrocarbons through casing. When used with a porosity log obtained in open or cased hole a water saturation can be calculated. The TDT water saturation computed in high porosity and high salinity situation approached the accuracy obtained from an openhole suite of logs. Since a high salinity and low porosity situation exists in many areas of West Texas, special interpretation techniques must be used to compute a semi-quantitative water saturation in these horizons. Examples of logs recorded in West Texas attest to the validity of these interpretation techniques.

In fluid-injection projects, the channeling or bypassing of injected fluids through fractures and high-permeability stringers results in poor reservoir sweep efficiency and low oil recovery. When the injected fluid is water, channeling problems have a less severe impact on the flood economics because water is relatively inexpensive, and it can be recovered and recycled through the reservoir to recover additional oil. However, many of the improved oil-recovery processes employ expensive fluids such as surfactants, micellar fluids, and solvents, which must produce oil during a single pass of a relatively small volume through the reservoir. Therefore, it is important to identify and correct any serious reservoir heterogeneities which would lead to channeling and to the inefficient use of the expensive improved recovery fluids. Some knowledge of the near wellbore reservoir heterogeneities can be derived from well logs and core permeability data. Pressure transient and pressure pulse tests are useful in detecting interwell fractures and in determining interwell communication. Other information is sometimes available from prior waterflood performance. A supportive method of determining reservoir interwell anatomy and reservoir performance in an improved recovery process is the tracing of interwell flow of injected water during an initial waterflood. During the past several years, the results of approximately 20 tracer programs that have been conducted in reservoirs undergoing waterfloods, gas drives, and alternate water-solvent injection have These tracer programs have provided the proving ground and the opportunity for screening the performance of numerous water and gas tracer materials and for arriving at a suite of "preferred" tracers for waterfloods and gas drives. This paper discusses the use of chemical and radioactive tracers to identify sweep problems in a tertiary miscible pilot area in West Texas, two potential micellar pilot areas in Wyoming, a Wyoming waterflood, and a hydrocarbon miscible project in Alberta, Canada.

Well flow analysis is the examination of well performance based on fundamental mathematical models of flow in well tubulars and flow through porous media. It is used to assign the pressure drop to each part of the flow path existing between the well drainage boundary and the wellhead pressure. Many types of computer software are available to perform the calculations and plot the results in an easy to read chart of well head pressure versus flow rate. Multiple curves can be generated so that actual performance can be compared to predicted performance for different wellbore conditions. Such curves will be used in this presentation to evaluate performance of different wells. One case study will demonstrate the use of well flow analysis to define the wellbore condition after perforating a gas well in South Texas. Well bore condition is defined by the perforation geometry and near perforation permeability. A pressure build-up test will be analyzed to provide a skin factor. This skin factor will be further evaluated using a simple, steady state, radial flow model for perforations to determine the near wellbore permeability.

Since the start of gas-lift, especially intermittent gas-lift, the need was felt for something to go between the base of a liquid slug and the gas that was pushing it up in a pipe.

The Vapor Jet System is an alternative to conventional vapor recovery technology for the recovery of hydrocarbon vapors from oil production facilities" storage tanks. The process utilizes a pump to pressurize a stream of produced water to serve as the operating medium for a jet pump. The potential energy ( pressure ) of the produced water stream is converted to kinetic energy ( velocity ) in the jet pump. The high velocity water stream entrains the near atmospheric pressured vapors and returns them to the facilities" low pressure system for separation and sale. The water is then returned to the water storage tanks for further de-gassing and reuse in the Vapor Jet System process, disposal or injection. The Vapor Jet System is simple, cost effective and virtually maintenance free. The Vapor Jet System can be installed for significantly less than compressor based systems and over the life of the installation operate at a fraction of their operating expenses.

The Walnut Bend Field is located approximately 65 miles north of Dallas in Cooke County, Texas. The field was discovered in 1938 by Sinclair. ARC0 is the operator of Unit 1 and Unit 2 along with 10 other 100% working interest leases. Most of the current production comes from Unit 1 and Unit 2.