Ion selective electrodes (ISE) can accurately measure the strength of hydrogen fluoride (HF) acids used for acidizing jobs. The accurate measurement of free fluoride generated from the hydrolysis reaction, especially with weaker organic acids, is important to ensure that the desired acid fluid strength is delivered downhole during well stimulation operations. 

Unlike inorganic acids such as hydrochloric that dissociates completely, organic acids only partially dissociates in solution, and as such do not completely hydrolyze the fluoride ion source such as ammonium fluoride or ammonium bifluoride to generate the required amount of HF. Furthermore, the presence of multiple dissociable protons with different acid strengths on organic acids such as citric acid and Etidronic acid further exacerbates the problem.  Therefore, there is the need to accurately measure the amount of hydrogen fluoride generated for acidizing fluid treatments.

Treating for paraffin in rod pumped wells is a critical operating cost driver that needs continuing attention.  While there are various prevention chemicals, operators still need periodic removal interventions.  This paper will summarize prior investigations regarding the removal of paraffin and provide a case history that illustrates the issues.

In addition, this paper will discuss the economic considerations related to common paraffin removal processes.  The economic considerations will include the direct costs as well as the indirect, hidden costs.  In general, paraffin removal in rod pumped wells by annular hot oiling has severe depth limitations that require periodic, supplemental treatments.  The economic benefits and trade-offs are largely dependent on the depth of paraffin deposition, the type of paraffin, and the wellbore configuration.

This paper will discuss the need for the oil industry at all levels to broaden its perspective regarding how the concept of hydraulic fracturing is communicated to the public.  The current level of communication is so narrowly focused that groups outside of the industry have been able to exploit this communication problem to the detriment of the industry.   This paper will discuss specific examples of the  communication problem and the corresponding economic and political impacts on the industry.

The Set a Seat is a tool that has been developed by Peak Completions Technologies that has reduced the cost of post frac operations.  Using Peaks patented technology, the Set a Seat make it possible to open up the well head and begin producing with milling out plugs. 

Today, E&P companies are being challenged to improve economic performance. Since completions are a major cost, it is imperative to improve completion efficiency and maximize production results.  A new controlled approach to multistage completions combines predictable frac placement (spacing and propped volume) with bottom-hole pressure and temperature data recorded during stimulation to enable progressive, formation-specific optimization of stimulation designs and frac delivery. The approach relies on single-point frac placement, using a coiled-tubing-deployed isolation system that incorporates downhole data recorders. The presentation describes single-point stimulation technology, discusses the value and interpretation of downhole pressure and temperature data, and reviews a number of optimization case histories.

Around the world, the focus of completing and stimulating wells has been based mainly on the efficiency of the completions and stimulation. While this is sound, too little focus has been paid to where the oil, gas and water is originating. Enormous opportunities abound to go back into these wells and evaluate them to determine the best candidates and zones to refrac.

This presentation will introduce an evaluation method, The Refrac Road Map,™ that has been tried and proven to be successful in several horizontal wells in West Texas. The Refrac Road Map™ is the updated version of this technology, designed to obtain more information than the previously mentioned system above. The previous system was designed and used to locate where water and oil were originating in an open hole carbonate well in West Texas and New Mexico. The updated version of the system has the following features:

• Isolates a perf cluster or sleeve

• Produces that isolated section of the well

• Directly measures

o  3 phase flow

o Static and Flowing bottom hole pressure

o Temperature

• Sensors

o Ultrasonic Doppler flow measurement

o Gas holdup: Optical Probe

o Water Hold Up: Electrical

o Oil Detection: Fluorescence Probe

The nature of horizontal wells makes standard production logs unreliable. This system isolates each zone, thus allowing true measurements rather than analysis of the mixed fluid in the lateral. With this data and mechanical diversion, we believe that refracs will become much more successful and profitable in the future.

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.