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The pump card has three load reference lines 1) Zero Load line, 2) Fluid Load, Fo, from Fluid Level, calculated using the pump intake pressure determined from an acoustic

Refracturing can be used to increase production in poorly fractured wells. A different application of this technology is to refracture wells with strong initial fractures. In this paper, we provide evidence of increased production due to refracturing two tight gas wells having deeply penetrating initial fractures. Surface tiltmeter measurements show refracture orientations at oblique angles to the azimuth of the initial fractures.

The developoment of a new cage for bottomhole sucker rod pumps was initiated by Oxy Petrolem to solve prematrue failures of existing cages in their water flood fields. Oxy approached Quinn's with the purpose of designing a cage in the Wasson/Clearforks area.After reviewing the wells, Quinn's designed a new cage that is a one piece cage, can handle an alternate pattern ball, have better flow characteristics with less pressure drop than any existing cages, and handle deep, corrosive well conditions.Quinn's utilized their finite element anaylysis software to design this new cage.

The bottomhole sucker rod pump, is the workhorse of artificial lift around the world. If the bottomhole sucker rod pump becomes fouled, the oil company is losing revenue. Prior to calling the service rig, this paper will provide a series of pracatical procedures to tyr BEFORE the service company is called. The goal is to restore pump function and return production to normal, while keeping lifting cost down.

On many occasions lost circulation is associated with stuck pipe and once circulation is regained the pine may become free. With a good mud system sometimes it is not advisable to contaminate the mud with other fluids; however, with Nitrogen the mud may be circulated through a degasser or across the shale shaker to break the gas out leaving uncontaminated mud. Nitrogen technical manuals will show pressure gradients of commingled nitrogen and liquid densities up to 11 lbs/gal. All gas laws are incorporated into their design.

This paper addresses one method of dealing with produced gas containing carbon dioxide (CO2) and hydrogen sulfide (H2S) in C02 secondary recovery projects in the Permian Basin of west Texas and southeast New Mexico. Reinjection of produced gas is becoming more common as Permian Basin C02 floods mature. Reinjection can be very cost effective, environmentally prudent, and technically beneficial. Reinjection reduces or eliminates sulfur emissions, reduces capital costs by eliminating sweetening facilities, and often reduces the cost of injection C02 purchases.

Optimization of effective fracture area is among the principal tenets of fracturing design engineering. It is well understood that effective fracture area is a first order driver for well productivity, and that optimization of effective fracture area is often critical to economic exploitation of reservoir assets. Extensive testing in a large-scale slot apparatus was conducted to evaluate the relative effects of various component and treatment parameters on the proppant transport capability of various slurry compositions.

Although fluid viscosity reduction is commonly used to gauge polymer degradation and viscosity reduction does indicate that polymer degradation has occurred, it is misleading to conclude that reduced viscosity equates to improved fracture conductivity or retained formation permeability. Polymer fragments which result from the normal breaking of gelled, cross-linked fracturing fluids no longer contribute significantly to fluid viscosity but do contribute to proppant pack and/or formation permeability damage.

This paper presents a method of estimating the reliability and expected operating time for injection units. An analysis of failure observations is presented and the means by which statistical methods can be employed to obtain reliability estimates. Expected operating times incorporating repair periods are developed and an example presented to illustrate the application of these techniques.

Effective waterflooding requires that injected water be condifed to and moved through the zones of permeability containing the remaining oil in place after primary production. The injection waters available for waterflooding are becoming more and more limited; therefore, this supply must be more efficiently utilized through confinement to the zones containing the secondary oil-in-place.

The economics of secondary recovery is certainly important to today's domestic oil industry. There is, however, another important consideration which must be taken, in view of present shortages of proven reserves-ultimate recovery of secondary oil. In other words, can more of these known reserves now in place in reservoirs already drilled and under waterflood be produced economically? Obviously, no oil will be banked to a producer if no water is injected into the section containing the moveable oil saturation which remains after primary production is accomplished.

This presentation discusses the results of experimental and field case studies of a remedial treatment technique designed to eliminate fracture proppant production. This process uses a low-viscosity consolidating agent, which is placed into the propped fractures via coiled tubing or conventional tubing coupled with a pressure-pulsing tool. The treatment fluids are designed to provide consolidation for previously placed proppant near the wellbore without damaging the permeability of the proppant pack.

Remote production management systems involve several basic configuration components. These components can be thought of as building blocks comprising a system. For the purpose of our discussion we will represent or conceptualize major components and their respective detailed facilities by means of block diagrams.

Modern stimulation treatments involve recording of a variety of data including surface rates, wellhead pressures, liquid additive rates and other parameters related to the fluids and proppants being applied as shown in Fig. 1 8, 2. In recent years, computers have been used not only to track and evaluate such treatments but also to model bottom-hole conditions in an attempt to simulate fracture geometry in real time during the treatment. Much of this work has centered around three dimensional models such as noted by Meyer1j2 and Cleary3.

This paper will discuss a method for the success till removal of scale deposits and perforation damage that inhibit the productivity/injectability of a well by the usage of a downhole tool that creates low frequency (16-40 Hz) oscillations in the wellbore fluid. Other methods for addressing the problem of scale and perforation damage will be discussed with a comparison of how and why this method proves to be more effective.

Iron sulfide scales vary in composition; this paper, in three parts, describes how a thorough analysis of the scale is necessary to optimize the chemical treatment and successfully remove the damage. The first part describes the different types and compositions of iron sulfide scale and the need for a tubing cleanout prior to an acidizing treatment. The second part describes the detailed analysis of the scale through the use of quantitative X-ray diffraction analysis and elemental analysis by energy dispersive X-ray. The third part of this paper presents scale removal treatment case histories.

Optimising the recovery of hydrocarbons has led to an increasing need for remedial applications in both production and injection wells. The increasing use of multi-zone horizontal completions, both for shale and more traditional formations, means thousands of frac ports are now being run every year. In 2010 a new technology was launched in North America to expand stainless steel patches using a high pressure inflatable packer. This has now become a regular service, both for perforation shut-off and casing repair.

Converting beam pumping wells to plunger lift drastically cuts costs, improves profit. and keeps marginal producers profitable. This paper discusses one such case for a West Texas Field. The majority of the wells converted to plunger lift showed equal or more oil and gas production after the conversion. Some of the wells increased gas production by almost 2009/o. Twenty-one wells (11% of the total number of wells) have currently been converted to plunger lift.

The Delaware formations are submarine channel/fan sands that are difficult to characterize. In this study, new methods have been applied to characterize the East Livingston Ridge Delaware Field. Using well logs, a complex 3-D reservoir model, composed of six layers and a meandering channel, was constructed to represent this geological depositional setup. Due to drastic changes in layer lithologies, determining multiple oil/water contacts and water saturations required a detailed well log interpretation.

Current drill-stem test pressure-recording techniques rely on a pressure sensor, a chart recorder and a clock. Analysis and interpretation of this recorder data can only be done after the tool string is retrieved from the well. The subject of this paper is a computer-based system that monitors, records, analyzes and displays at the wellsite, supplying the reservoir data necessary for the well operator to make a production decision about the well.

The Means field, located in Andrews County, Texas provides an excellent opportunity to observe the evolution of reservoir management to meet changing economic and technical challenges. The Means field was discovered in 1934 and developed on 40-acre [16-ha] spacing. Reservoir management techniques began within one year of discovery and have continued with increasing complexity as operations have changed from primary to secondary to tertiary. In 1963, a major portion of the field was unitized as the Means (San Andres) Unit (MSAU), which will be the subject of this discussion.

The Means field, located in Andrews County, Texas provides an excellent opportunity to observe the evolution of reservoir management to meet changing economic and technical challenges. The Means field was discovered in 1934 and developed on 40-acre [16-ha] spacing. Reservoir management techniques began within one year of discovery and have continued with increasing complexity as operations have changed from primary to secondary to tertiary. In 1963, a major portion of the field was unitized as the Means (San Andres) Unit (MSAU), which will be the subject of this discussion.

The reservoir average pressure can now be evaluated from routinely available rate and flowing pressure production data, using an extension of the reciprocal productivity index method. Traditionally, reservoir average pressure could only be determined from an extended duration build-up test. Especially in low permeability, stimulated reservoirs, that procedure generally tends to underestimate the pressure, due to practical limitations on shut-in times. In addition, an error in the reservoir average pressure determination results in an error in the computed skin for the well.

This paper is concerned with the application of sweep out behavior in estimating oil recovery from hydrocarbon-bearing reservoirs. It reviews the theory of sweep efficiency and related concepts. Parameters studied include the influence of fluid motilities on sweep out performance, the consequential entrapment of oil due to well pattern geometry, permeability-porosity inhomogeneity effects, and results of stratification of the producing zone on sweep out performance. Remedies for some of these problems are suggested. Numerous field examples are cited.