Traditionally, ball-drop completion systems were limited not only by application, but by pressure, rates, and stage count. This paper shows the history of the ball-drop completion systems in the Permian Basin and looks at how the development of new technology has allowed ball-drop systems to be used in more than just open hole applications, as well as how this technology has overcome the aforementioned limitations.

A new technique of delivering long-lasting treatment for damaging well conditions, such as scales, corrosion, or organic deposits, has been achieved using a novel technology. This new technology involves a viscoelastic, biopolymer-hydrogel as the matrix to incorporate and transport chemicals into the formation. When placed in the fracture length, the porous matrix controls the release of the treatment agent over long period of time.

The system is environmentally safe and cost-effective, and designed to be pumped with stimulation fluids during proppant transport. This technology has proven to provide a more efficient delivery, placement, and long-term chemical treatment compared to other existing technologies, where maximum loading of the product is restricted to below 2% of the total proppant.

The Permian Basin (PB) presents many challenges in the development of unconventional plays, such as varying pore pressures, high treating pressures, and geological uncertainty. These challenges intensify in areas that are not well developed or understood. A collaborative partnership between the operator and service provider can significantly reduce such risks.

This paper discusses such a collaborative partnership in the PB wherein considerable benefits were gained during drilling and completion of six wells. Using lessons learned and new technologies, the operator and service company engineered a workflow to overcome challenges and deliver economic results, which significantly outperformed previous wells. Key challenges faced and how they were overcome are discussed.

These efforts resulted in a six-month cumulative BOE increase of 32% from offset wells. The foundation of this success is directly attributed to the collaborative partnership between the operator and service  company using an engineered workflow to achieve a common goal.

Wax deposition in offshore and onshore pipeline is one of the significant current flow assurance problem.  There are several wax deposition models proposed in the literature.  However, all of them are validated based on the limited number of data and have not been crosschecked with other researchers’ data.  All of wax deposition model on turbulent flow contain the unknown physical parameters which required in wax deposition prediction.  

Nevertheless, the closure relationships of the unknown parameters are not provided in most models, and the available correlations require the validations against more experimental data.  This work provides the performance analysis of wax deposition models by testing the proposed models (such as Singh et al. (2000)) against the experimental data that are just recently available.  The contribution of this work is the understanding in the uncertainty and the limitation in wax deposition model currently available in several commercial software.

There is so much data being collected on each well site increasing the success to a company’s maintenance programs.  When wellbore surveys identify hole deviations those specific areas can be targeted as potential premature failure points. These critical points down hole are many times 

found to be areas where problems initiate causing work over shut downs. Nondestructive testing of tubing while pulling out of hole gives very essential sequential confirmation to the well’s actual deviation situation. 

When correlating surveys to tubing profiles wear is an important element needed to analyze excessive rod on tubing wear making data very useful to assist with stroke control, rod guiding, reducing work overs and decreasing well down times. The majority of wells, used tubing is not inspected it’s just pulled and replaced when a well failure occurs. Nondestructive testing tubing in many ways provides valuable well information to know where leaks may have occurred. 

There are 3 ways that was used to make packers: inflatables, Hydro-mechanical, and swellables. Using Expandable Steel as the reinforcement of a sealing system is an innovation that allows unseen features to the market. A long history of using Expandable Steel in Casing Patch operations allowed Saltel Industries to develop unique ways to create isolation systems with expanded metals.

The Saltel Expandable Steel Annular Zonal Isolation Packer (SES Packer) is designed in a unique way. It is slid onto the casing, before both of its extremities are fixed by welding or crimping. High pressure inside the casing (or a straddle tool) is then transmitted inside the packer through an expansion port. This triggers the plastic expansion of a steel barrier which will mold inside the borehole, sealing-off the annulus for the life of the well. This simple philosophy enables Saltel Industries to provide reliable and cost effective annular isolation packers for a variety of applications.

Its simple design increases the reliability and the success ratio of the operations, as well as its cost efficiency. With no moving part, and reduced length and OD, it is sturdy to go to reach TD safely. The packer molds the formation or casing even of oval or out-of-gauge boreholes. By controlling very accurately the expansion of the metal sleeve, the operation allows to predict the stresses that will be applied to the formation. It can sustain a significant axial load before, during and after treatment. It seals even with severe temperature variations. It is sealing for the life of the well.

The sealing profile and pressure compensation systems are tailored to fit the application needs. The innovation brings:

• An increased reliability and lifespan to ECP (External Casing Packers) used in cement stage operations, with a gas tight efficiency and a 10,000 psi internal pressure rating to sustain frac pressures.

• A slim profile for existing well isolation to mitigate the ID loss for Refrac or Remedial application with the Slimline Packer

• A 10 to 15k differential rating even with temperature drops with the FracPacker used in Open-hole completions (with ball-drop sleeves of CTAS)

• A preserved Well Integrity after the setting of the Well-Integrity Annular Zonal Isolation (WI-AZIP)

This paper will describe in details the advantages of Expandable Steel technology applied in Casing Patches and in Packers for those applications, and will go through the necessary qualification process used for demanding environments.

Anadarko Petroleum Corporation operates numerous deep water production facilities in the Gulf of Mexico (GOM). In a continuing effort to maximize production and the recovery efficiency of existing assets, Anadarko has invested heavily into researching effective methods and practices of remediating asphaltene inhibited wells in a bid to offset premature well decline. 

At the heart of Anadarko’s efforts to maintain production in asphaltene compromised wells is a vessel-based stimulation program that seeks to remediate production losses by reverse injecting volumes of various solutions (namely xylene, diesel, and/or dry oil) in a bid to flush detrimental asphaltene deposits away from the lower completion zone. 

This paper will review a comprehensive analysis and the findings of a project undertaken in the summer of 2015 to examine and identify the most efficient stimulation techniques for wells experiencing compromised production due to asphaltene deposits. Specifically, this paper will establish the most effective stimulation fluid to be used, the optimal volume of fluid to be injected, and the most cost effective frequency of treatment.

The shale revolution in the continental United States has reinvigorated the Oil and Gas Industry. According to the EIA, shale plays account for around 49% of total U.S. crude oil production. Although much progress has been made to be more efficient time and money wise; there are still technical issues that are being addressed.

Drilling through shale has many obstacles that plague the industry. It is well known that shales have a strong affinity for water. When water is absorbed, the stability of the shale is reduced. Cohesive strength is reduced which causes the shale to either expand or crumble. The amount of water absorbed depends greatly on the characteristics of its clay mineral and the ionic concentration of surrounding fluids.

This study takes a literary review of well-bore stability of unconventional shale plays in the United States and methods to improve drilling practices to account for this issue.

Pressure maintenance is a secondary oil recovery method which involves injecting another immiscible fluid (e.g. water) to support the oil sweep from a depleting zone. Through reservoir simulation, Tately NV Company attempts to evaluate the benefit of pressure maintenance through water injection on oil recovery from one of its zones in its field in Indonesia. This is because in this particular zone, the pressure around some of its producers has depleted severely after only the first few years of production. This paper attempts to review the process Tately NV has used to perform history matching in order to validate the reservoir dynamic model and obtain the optimum water injection well count, injection schedule, and injection rate.

From 1979 to 1982, the oil industry experienced a continual rise in the rig count. This ever expanding number of rigs caused the service company industry to undergo rapid expansion both from the standpoint of people and equipment. It was obvious that many of the companies looked at an ever increasing, upward spiral and planned expansion and requirements on that continued growth. The decline in rig count, which actually started in late 1981, was even more drastic than the upward spiral. Many service companies and suppliers for those service companies who had become highly leveraged found themselves in a very precarious position. In order to capture an ever declining market, many service companies resorted to extreme price cutting on available jobs. An examination of the profits of five representative companies during the good years is evaluated and compared to the profitability of companies during 1982 and early 1983. The response of both the service companies and the oil companies in a survival mode are evaluated. The keynote of the paper will be directed toward the free enterprise system, profit motivation, and ultimately, the survival of the oil service industry as we now know it.

During the past 18 years, rodstrings installed with a properly designed Sinkerbar Section have proven to reduce downstroke buckling and maintain tension in all rods. Results from use of these rodstring designs have been reduced rod-on-tubing wear and extended tubing and rod life. During the past 5 years, use of high-density polyethylene liners in oilfield tubing has shown to increase wear resistance and reduce the coefficient of friction. Results from use of these liners in tubing have been reduced rod- on-tubing wear and extended tubing life. These successful oil field products and their benefits have been combined to develop a high-density polyethylene sleeved Sinkerbar called a Polybar. During this test, these Polybars exhibited the resistance to buckling of a Sinkerbar with the wear resistance and coefficient of friction of polyethylene. This paper presents results of a 2.8 year field test involving five (5)-producing wells installed with Polybars. The documented results show that no tubing leaks occurred in tubing protected by Polybars.

Projecting the future availability and cost of petroleum for 20 to 40 years into the future is an important, but very uncertain task. Periodically various authors project a significant shortfall of petroleum availability in just a few years. One recent March 1998, popular press example is in Scientific American". This information has also been published in professional journals as cited in the article. This information suggests that OPEC has overestimated its reserves by significant amount beginning in late

Stringent safety requirements imposed by major operators when fluid level measurements are performed offshore or in enclosed wellhead spaces such as in Alaska’s North Slope create procedural complications, such as the requirement for hot permits, when performing fluid level measurements in producing wells. This need has been eliminated by the development of a small, self contained, fully digital, battery powered instrument that is approved for use in hazardous areas. The Echometer Model H instrument has been tested at various locations. It facilitates the acquisition and interpretation of the data through an advanced software package that virtually automates the analysis even in acoustically noisy environments. Results are observed immediately on the instrument screen then saved in the data base for eventual transfer to corporate records. This paper presents detailed information about the new system and reviews data acquired in gas lift wells, flowing gas wells and ESP installations.

Sucker rod coupling friction values are used by rod design software to calculate rod loads for bare steel tubing on steel couplings.  The friction values for sucker rod couplings on HDPE lined tubing is not known or defined. Therefore, rod load calculations in HDPE lined tubing are problematic. Tests were performed to compare the coupling friction in HDPE lined tubing compared to bare steel tubing at various temperatures and side loads. The objective was to find the drag ration of rod couplings on HDPE lined tubing to that of bare steel tubing at various termperatures.  The data was used to develop an equation to calculate the drag in HDPE lined tubing to that of bare steel tubing as a function of temperature. Although not quantitatvely analyzed in this study, a significant side load capacity difference between HDPE lined and bare tubing was also observed. 

This paper presents three years of field experience showing dramatically improved rod string performance, resulting in lower intervention costs.

There are three key factors in achieving this improved performance. First and foremost is the rigorous application of best practices for rod handling, connection cleaning, preparation and lubrication. Second is the use of a fully automated rod tong which delivers accurate CD control on every connection in the string. She third factor is a secondary measurement of true torque for each connection, giving further assurance that proper pin tension is achieved.

This experience has demonstrated that API 11BR does contain the proper recommended practices for successful rod makeup. Suggestions are presented for future topics which could be considered for further enhancement of API 11BR.

In Greater Green River Basin, Wyoming In order to keep capital cost down in tight gas fields, the slimhole 3%" wellbore was developed. Due to the large pipe diameter, high line pressure and low rock permeability, liquid loading becomes an issue early on a wells life cycle and, in most cases, liquid loading is immediate upon first delivery. 3%" plungers have proven to be an effective method for deliquification of the slim hole wellbore utilizing the larger-cross sectional area to effectively push the plunger and accumulated liquids up the wellbore. In comparison, using the Foss & Gaul Calculation, the 3%" plunger can operates with a lower differential pressure across it than smaller tubing sizes. The 3%" slimhole plunger has been successful in restoring production to the original decline curve or eliminating the hyperbolic decline recognized when liquid loading occurs. 3 %," plungers are currently pushing the existing fluid lifting limits and new 3%" plunger technologies such as freecycle plunger lift systems are under evaluation. In this paper the authors will describe the process of evaluation that was used and provide details of the operational problems that were encountered and how they were handled. They will go on to provide production data for several case study wells that illustrate the effectiveness of the plunger lift system and its close adherence to the performance predicted in the evaluation process.

This discussion deals with the packed hole assembly drilling technique to "controlled deviation drilling," how one tool can be used to help accomplish this both economically and easily, and proof of the performance of this tool.

The need to produce large volumes of fluids from secondary recovery wells, and to produce normal levels of fluid from deeper wells, made possible an innovative artificial lift option using a Dual Displacement Pump.(Fig. 1) Reciprocated with a standard beam pumping unit using coiled tubing, this production system (patent pending) consist in reciprocating a plunger of a down hole pump, were both motions of the pumping unit are utilized to convey fluid to surface. While in the down stroke production reaches surface through the annular space between CT and production tubing, in the up stroke fluids reach the surface through the annular space between CT and production tubing, The pump design incorporates two independent sets of traveling valves and two sets of standing valves with only one Plunger/barrel configuration.

This article covers the actions taken and results obtained in controlling sucker rod pin failures in the period 1963-1983 at the Cerro Dragon Area, Comodoro Rivadavia, southern Argentina.

The term "hydraulic pumping system" as used herein, is taken to mean a particular method of lifting fluid from oil reservoirs, in which a power pump, distribution lines, subsurface pumps, and other auxiliary components are employed. Some of the most familiar manufacturers of this type of pumping equipment are Kobe, Inc., Sargent Engineering Corporation, and National Supply Company. Sometimes this system is referred to as "hydraulic rodless pumping", but in the strictest sense this is untrue because there is always a rod connection the engine and pump pistons. However, sucker rods are not required in this mechanical reciprocating pump, which may have contributed to this system being termed "rodless". It is very difficult to compare one pumping method with another unless the comparison is restricted to specific applications.

It is probable that more effort has gone into a study of corrosion control in the Brown Bassett Ellenburger Field than in any other single gas field. This is as it should be, since the corrosion problems encountered are more severe than those generally encountered.

The Pressure Fluctuating Tool (PFT) utilizes a bi-stable, fluidic oscillator to create pulsating pressure for breaking down and/or cleaning up perforations in oil, gas and injection wells with or without stimulation fluids. The pressures generated by the PFT are from 1,500 psi above hydrostatic to 1,500 psi below hydrostatic at 140 to 150 cycles per second. This focused energy has been very successful in perforation tunnel clean up as will be indicated in the detailed case history review contained in this paper.

The cost of conventional methods of paraffin control in pumping wells is often high. This paper describes an experimental installation for the injection of butane on a pumping well in Carter County, Oklahoma, in 1958, and subsequent expansion of the process to eight other well. The frequency and quantity of injection varies with the prevailing surface temperature conditions, and to date only minor problems have been encountered using the butane injection process.

As with all industries, the fracturing industry has gone through many technological advances over the years, and with these come many successes. Using a low polymer energized fluid seems to provide a good solution for these types of problems. These new style treatments provide faster cleanup, better flow back, good sand placement, and better production than conventional or previous fracturing fluids. The case studies provided will show that this treatment fluid technique provides a positive response for these types of wells. Low-polymer energized fluids can provide the qualities and properties to enhance completions and improve project and well economics.

This paper is a case study of the selection procedure for the various types of artificial lift equipment utilized in the Reinecke Unit, Reinecke Field, Borden County, Texas. The considerations involved in choosing a Jet pump, Submersible pump, or Rod pump for maintaining optimum production performance in a high capacity reservoir are reviewed and evaluated.