Continuous sucker rod had been used for many years in sucker rod pump applications. However, several challenges have limited its acceptance in the past. The availability of service equipment, welding methodology, and selection of metallurgy all contributed to premature failures and operator frustration with the timeliness of installation and repairs.

A new approach to implementing continuous rod started with establishing a robust service infrastructure to install and repair the rod. Improved welding procedures and personnel training addressed a frequent point of past failures. Changes in the design approach and sizes used enabled new opportunities that may have previously not been addressed with continuous rod. A shift to metallurgy more similar to the predominant grade used for conventional sucker rods aims to improve fatigue resistance of continuous rod in corrosive environments.

The changes in material and service capability are enabling longer run times, reduced workover time, and extending the capabilities of rod pump wells to produce greater volumes at deeper depths. Multiple installations in the Permian Basin will be discussed to demonstrate the recent successes seen with continuous rod. 

Artificial Lift systems are crucial in optimizing production for horizontal oil and gas wells. As these wells face rapid reservoir pressure decline, increased gas and solids production, high deviation in well geometry, and unstable flow regimes selecting an appropriate artificial lift method becomes paramount. By implementing the right artificial lift system, operators can counter these challenges, maintain consistent flow rates, and maximize hydrocarbon recovery, ensuring sustained and efficient production throughout the well’s operational life. 
Electric submersible progressive cavity pumps (ESPCP) combine the benefits of an electric submersible pump (ESP) and a progressive cavity pump (PCP). The main advantages of an ESPCP are:
• Eliminates mechanical wear of rods and tubing.
• Suitable for deviated and horizontal wells.
• Same benefits as PCPs for solids handling and producing viscous fluid.
• Production rates can vary with the use of a variable-speed drive.
However, the ESPCP system with a traditional PCP is commonly used in heavy oil applications. Large gas volumes present in light oil formations tend to swell the stator elastomer, leading to lower efficiency and system failure. Besides, a conventional PCP has a limited temperature capability of up to 185 degF and is very sensitive to aromatics.
This abstract is about a new high-efficiency and reliable system capable of overcoming the main challenges in Permian’s operations: gas lock ( because of high GVF), high power consumption with traditional artificial lift systems for low rate applications, solid productions, parted rods, hole in tubings, among others.
Combining a permanent magnet motor (PMM) and a composite PCP, results in a more efficient pumping system that:

• Lowers power consumption and CO2 emissions reduction
• Increases production by setting the pump deeper, adding more lifting capacity
• Eliminates up to 80 % of failures of wells (elimination of rod string failures)
• Improves equipment reliability due to the elimination of a gearbox (the most common type of failure for ESPCP) 
• Allows for ESPCP production in light oil applications (up to 45 API)

Objectives/Scope: 
A new methodology for automatic iteration on viscous damping enhanced with state-of-the-art pump fillage, fluid load lines and valve openings and closing calculation is presented. Field results showing the impact of the methodology in diagnosing downhole conditions, improving inferred production, fluid level, pump intake and horsepower calculations are shown.

Methods, Procedures, Process: 
The new approach uses a wave equation model with iteration on viscous damping paired with a traveling valve and standing valve calculation. Pump fillage and fluid load lines are calculated, which enables calculation of mechanical friction. The iteration uses a bisection method-like algorithm, which speeds up the convergence and removes the algorithm’s dependence on horsepower convergence criteria and other fluid and well variables.

Results, Observations, Conclusions:
In sucker rod pumped wells, efficiency and control of the entire system is ruled by elasticity, viscous friction and mechanical friction. Elasticity comes from the elastic behavior of the rod string and the propagation of stress waves due to the cyclic pumping operation traveling up and down the rod string at the speed of sound. Mechanical friction results from the rod string, couplings or pump coming in contact with the tubing. Viscous friction originated from produced fluid imparting a viscous force on the outer diameter of the rod string during operation. Those three factors are the basis for the calculation of downhole data from surface data to enable optimization and better control of sucker rod pump applications. Neglecting viscous friction leads to erroneous downhole data.
Very often, downhole cards have an over loop appearance which is physically impossible when considering pumping unit dynamics. This is due to the viscous force not being adjusted properly. Also, what can be mistaken from mechanical friction can be in fact completely removed from downhole data using appropriate viscous adjustment. Finally, operators traditionally overestimate their inferred production from the extra fictive load that is present on a poorly viscous friction adjusted card. The field data results presented in this paper show this new approach eradicates all these issues to deliver accurate and truthful downhole data.

Novelty:
The new approach iterates on the optimal damping factor for both the upstroke and downstroke for every stroke. Currently, most controllers utilize a manually adjusted damping factor, which leads to the damping factor not being adjusted for every stroke. Repercussions of this include overestimation of inferred production, overlooping phenomenon and appearance of excessive mechanical friction. 

Environmental concerns and increasing costs are creating a need for a polymer that will allow the use of a high salt, high hardness water in the making of a viscosified frac fluid. Any new polymer would also need to tick the boxes for cost, rheology, HS&E characteristics as well as breaking in the reservoir. Past development efforts have focused on improving organic-based polymers. A new approach was taken and a shift was made to the use of silica-based polymer. This paper will review silica chemistry but the focus will be on West Texas field trials where the silica gel was used as an alternative to 20 lb/Mgal crosslinked-guar. Covered topics will include; chemistry of produced water, making the silica gel on-location, pumping characteristics, cost and impact on production.
 

This presentation will discuss a new method of locking out beam pumping unit using a patented and engineered hydraulic sheave lock to support reducing risk at the well site when the pumping unit is shut down for routine maintenance or workovers. It will explore merits of keeping workers entirely out of the swing zone, allowing personnel to accomplish tasks safely and easily, without risk of brake cable failure or slippage resulting in movement of the counterweights. The discussion will focus on how this approach impacts traditional operational practices including an analysis of key metrics encompassing the ability to reduce third party service costs, avoid near miss and serious safety incidents, while also reducing traffic at the well site, resulting in less road damage and carbon emissions. Discussion will focus on how this new process adds value by reducing costs and improving safety for producers. 
 

A revolutionary packer-type gas separator was designed to improve gas separation efficiency downhole. A deep analysis of gas separation methods was done to better understand the nature of the process and to design a tool that could generate enhanced conditions for the gas separation phenomenon. During the research stages where data from Permian fields were analyzed to develop this new design of gas separator, the engineering team found three main challenges in downhole gas separation. The first one was the wells were being converted from ESP to rod pump earlier, forcing the downhole gas separators to handle more production than before. The second is the small production casing size that usually is 5.5” casing, which significantly reduces the annulus area that is vital to get an effective gas separation efficiency, and finally, the gas slugging behavior, which in high proportion can lead to a gas lock-in sucker rod pump systems. Following the requirements and limitations, a packer-type gas separator was designed, built, and tested in oil wells. This gas separator has an outlet section of 1.89” OD, which means the design maximizes the gas separation area where it really matters at the fluid outlet point. The innovative fluid exit slots design creates a linear flow path allowing gas to separate and flow upward the casing annulus in a natural way. Additionally, a valve below the cup packer was included to eliminate surging in wells. This valve prevents surging by holding the fluid in the vertical section, thus avoiding backflow when the gas slug leaves liquids behind. To evaluate the new design, a calculator was developed to estimate the gas separation efficiency downhole and compare the gas separation efficiency among different gas separators. After the implementation of this design in 5 wells, the results confirmed the high gas separation efficiency obtained with this new gas separator configuration. The novelty of this gas separator design is the outlet section that takes advantage of the gravity force to increase the gas separation efficiency without limiting the tensile strength of the BHA. Also, the fact of including a valve to address the surging condition in the well before the fluids go through the gas separation is a new approach in a gas separation tool. 

The vast majority of hydrogen sulfide monitoring systems historically use the solid state, semiconductor, metal oxide film type sensor. This type of H2S sensor has some inherent traits which manifest themselves in the field as application problems. Examples of these application problems include lack of repeatability (span drift), partial or total loss of response with removal of power, frequent and complicated calibration requirements, desensitization with exposure to moisture and the need to subject the sensors to H2S gas between calibrations to prevent them from "going to sleep". The following is an in-depth explanation as to how and why these problems occur along with the hows and whys behind a recommended solution.

Gas passage performance of gas lift valves under dynamic conditions has only been studied in the last twenty years. Proper assessment of gas injection rates at valve operating conditions requires the use of sophisticated measuring and control equipment only a few companies possess; and involves tedious and time-consuming data acquisition procedures. As a result, many gas lift installations are designed even today without properly accounting for the dynamic behavior of operating gas lift valves. The authors applied a novel approach to the description of gas lift valve performance and used Computational Fluid Dynamics (CFD) techniques to determine the valve's gas passage characteristics. CFD calculations provide a numerical solution of the governing equations (like the conservation of mass, energy, etc.) that can be written for a flowing fluid. To facilitate the simultaneous solution of the governing equations the flow space (the inside of the valve available for gas flow) must be divided into sufficiently small final volumes i.e. cells. Since the accuracy of flow modeling greatly depends on the proper setup of these cells the paper fully describes their proper spatial distribution. After the cell structure of the gas lift valve was properly set up, CFD calculations allowed the calculation of the gas volume passed by the valve for different combinations of valve stem travels, injection, and production pressures; i.e. for static conditions. In dynamic conditions, however, valve stem travel is a function of the net opening force developing on the tip of the valve stem. Since this force can be found by integrating the pressure distribution on the valve stem tip, an iterative procedure was developed to describe the valve behavior. The final result of the proposed iterative calculation model is the dynamic performance curve of the gas lift valve i.e. the injected gas rate vs. injection, production, and dome charge pressures. The procedure developed by the authors gives gas injections rates very close to those received from the universally-applied RP

This paper deals with a new method of obtaining injection and producing well permeability profiles. The flow meter and nuclear fluid density tools and their use in analyzing reservoir behavior will be explained. Numerous logs obtained from secondary recovery projects and in producing wells for fracture evaluation and remedial planning will be discussed.

The present energy situation has required the oil industry to evaluate all feasible methods to sustain and increase production in order to keep pace with our energy needs. 'Lost production due to scale deposition has been a major problem in the oil industry and has plugged many a good well while reducing production in most others. Many different scale inhibition techniques exist today and all have varying degrees of success. It is well known that the most effective and least expensive way to protect against scale deposition is during the initial completion of the well before the problem occurs. Most well completions today include hydraulic fracturing operation using an aqueous crosslinked fluid. These fluids, however, do not lend themselves to the use of scale inhibitors due to compatibility problems. This paper discusses the incompatibility of crosslinked gels with scale inhibitors along with experimental results. This paper attempts to solve the incompatibility problem by proposing three models to run scale inhibitors in conjunction with aqueous crosslinked stimulation fluids. The three models proposed are based on computer studies using a "partial pad" approach. All models have been described in detail and the results of the study have been graphically illustrated. The paper also briefly discusses the different types of oilfield scales, their formation, deposition and mechanism of inhibition.

Long open-hole or heavily perforated intervals with stringers of varying porosities and permeability have always been difficult stimulation problems. In the majority of instances treatments have been staged, continuously, with various types of blocking agents. Only after the job was complete, could any down-hole evaluation of the success of the diverting agents be estimated. Obviously, critical information such as the extent of the formation treated per stage, communicated zones, channeling behind the pipe, etc. was unavailable until after the treatment was over.

The author will review the current status of a complete new approach is well servicing that includes: 1) A remotely operated robotic-automatic well services rig wherein there is no operating personnel within 100 feet of the wellbore. 2) An integrated system for making up tubing as well as the two element rod connection to absolute computer precision. 3) An integrated system for over the well electronic inspection systems of tubing and rods.

In Coalbed Methane (CBM) production wells using Electric Submersible Pumps (ESP), it is common to control fluid levels to the required setting by the use of Variable Speed Drives. However this can cause high harmonics and, as a result, in the Powder River Basin in Wyoming, power companies have become increasingly reluctant to allow the use of variable speed drives and an alternative method of well control had to be found. A totally new approach to controlling ESPs, and thus the well fluid levels, was conceived. The Weatherford Well Management System0 (WMS) is a self-contained alternative to variable speed drives, which eliminates harmonics problems. It consists of a motor starter, a motor protection system and a microprocessor which controls a surface actuated choke in the flow line. During production operations, fluid levels can be controlled by automatically adjusting the choke. This paper describes the conception, development and field testing of the Weatherford WMS as a viable alternative to variable speed drives for downhole pump control. This system, which can be made compatible with any communication system, though designed for ESP applications in CBM production, is also applicable to other artificial lif t systems and oilfield applications.

This paper explains a new approach in choosing the most acceptable treating fluid and a history of field applications using the new method.

The Coalbed Natural Gas Industry, or Coalbed Methane (CBM) continues to gain global popularity and momentum. However today, CBM operations are one of economic challenges. Varying coal seam depths, rapidly declining water production rates, uncharacteristic well completions, sand, coal fines, etc., prohibit using just one form artificial lift equipment. Successful CBM production operations demand multiple product lines. Weatherford determined that a new approach was needed that offered multiple product lines in addition to modifications of conventional artificial lift products. A presentation will be prepared that outlines the challenges CBM production presents to operators. This paper and presentation will discuss old artificial production techniques and new approaches. Because there is a never-ending focus on lowering lease operating expenses (LOE) operators continue to push manufacturers into modifying and or developing new production products. Weatherford has a dedicated CBM team determined to lead the industry in CBM equipment development. This paper will offer some of Weatherford's solutions to this ever-demanding industry.

In order to combat falling productivity and increased water production in the West Flowers and Guest (Canyon Sand) fields, a new approach to stimulation technique and fluid had to be initiated. It was suspected that many pre-1975 frac jobs probably were lost into unproductive zones resulting in very little stimulation of the actual pay section. To combat this situation, the frac fluid was changed to a very high viscosity cross-linked CM C-based polymer gel. The base fluid was 2% KC1 water treated with de-emulsifiers. A detailed computerized study was conducted to determine a near optimum treatment design. Fluid volumes were selected based on frac lengths which provided the most economically feasible productivity increase ratios (J/Jo) and proppant concentrations were analyzed so as to afford the optimum permeability contrasts. Sand concentrations were increased, and 10-20 mesh sand was used. The perforations are acidized and broken down. This is followed by a base temperature survey. A 2,000-gal dummy stage (slick water) is pumped to determine the zone taking fluid. If channeling is observed, a stage of a calculated amount of benzoic acid flakes is run to divert thef2uid into the pay section. A 2,000-gal dummy stage is next pumped. Based on the results of a temperature and radioactive survey, the fraction of the pay section taking fluid is determined. A proportional amount of frac is pumped followed by a calculated amount of block. This is followed by a shut-in period of 20 minutes to let the fracture heal and the surface pressure till about 500 psi. The above steps are repeated until all or most of the zone is fractured.

Horizontal completions in lower permeability formations often result in a need for effective hydraulic fracturing stimulations for many of these wells to reach economic production levels. Cost constraints seldom allow the use of methods such as cemented completions and individual fracturing of numerous zones with bridge plug isolation. Some newer methods require expensive downhole jewelry. By implementing a coiled tubing (CT) deployed hydrajet perforating method and pumping the fracturing fluid slurry down the CT/casing annulus, the operator can use lower risk liner completions (cemented or not). Individual zones are perforated, fraced, and then sand-plugged one at a time. With the ability to reverse up the CT between stages and after all fracs are completed there is only one CT intervention and one frac mobilization needed. The allowable frac rates can be quite high and stimulation costs are greatly reduced by being able to perforate/frac multiple times within the same day.

The South Cowden (San Andres) Unit is the site selected for one of three mid-term projects to be conducted under the DOE Class II Oil Program for Shallow Shelf Carbonate Reservoirs. The proposed $21 million dollar project is designed to demonstrate the technical and economic viability of an innovative CO2 flood project development approach. The new approach employs cost-effective advanced reservoir characterization technology as an integral part of a focused development plan utilizing horizontal CO2 injection wells and centralization of production/injection facilities to optimize CO2 project economics.- If proven successful, this new approach will help improve the economic viability of CO2 flooding for many older, smaller fields which are or soon will be facing abandonment.

Previous methods to detect and locate fluid flow behind well casings such as temperature, radioactive tracer, or acoustic noise have been successful but often difficult to interpret. An alternative method which is specific for detecting water flow (or CO2 flow) is the oxygen activation log. This paper presents field examples from West Texas of the Water Flow Log which is based on a new approach to oxygen activation logging. Each example demonstrates the importance of this measurement in obtaining a conclusive interpretation to difficult production problems caused from channeling fluids behind pipe.

Previous methods to detect and locate fluid flow behind well casings such as temperature, radioactive tracer, or acoustic noise have been successful but often difficult to interpret. An alternative method which is specific for detecting water flow (or CO2 flow) is the oxygen activation log. This paper presents field examples from West Texas of the Water Flow Log which is based on a new approach to oxygen activation logging. Each example demonstrates the importance of this measurement in obtaining a conclusive interpretation to difficult production problems caused from channeling fluids behind pipe.

The South Cowdeu (San Audres) Unit was selected as the site for one of three mid-term projects to be conducted under the DOE Class II Oil Program for Shallow Shelf Carbonate Reservoirs. The $21 million project was designed to demonstrate the technical and economic viability of an innovative carbon dioxide (CO2 flood project development approach. The new approach employed cost-effective advanced reservoir characterization technology as an integral part of a focused development plan utilizing horizontal injection wells, where appropriate, and centralization of production/injection facilities to optimize CO2 project economics. This paper will review actual implementation and field performance in the first eighteen months of the project, focusing on key issues of timing, stimulation, injection profile monitoring, reservoir pressure reduction, and conformance control A comparison will be presented of initial simulation model results with current predictions.

Cement-lined steel or iron pipe is not a new approach to corrosion prevention. In 1836 the French Academy of Science reported the successful use of cement-lined pipe. They reported that, "Hydraulic cement, applied about 2.5 mm (0.1 inches) thick, is of all compositions, combining facility of application and cheapness, that which adheres the best to the casting, is the most indestructible, and prevents most effectually all oxidation (Corrosion) and consequent formation of tubercles. Of course, it is well documented that the great Roman aqueducts were constructed of hydraulic cement, forerunner of modern Portland cement.

Conventional downhole treatments for scale and corrosion typically rely upon either "squeeze" or batch type treatments for control of corrosion and/or scale. These treatments introduce large amounts of inhibitor into the wellbore area and may adversely affect the production characteristics of the well, require excessive amounts of chemical, and require repeated treatments over short periods of time. The use of encapsulated materials for scale and corrosion inhibition has recently been shown to be a reliable and economic alternative to the conventional squeeze or truck batch treatment. Encapsulated materials provide a reliable, long term, controlled release of inhibitor at concentration levels high enough to provide the required protection without introducing potentially damaging chemicals into the formation. This paper details field experiences with the encapsulated materials in a variety of wells and the results that have been obtained with these treatments.

This paper offers a new approach to qualify proppant before fracture stimulation. Automated and patented flowing stream sampling technology, only recently available, is easily positioned between pneumatic trailer and field bin. Mobile labs are used to measure sample physical properties and correlate public domain or design data. Differences, which provide the basis for performance and engineering decisions, relate to mining anomalies, manufacturing defects, transportation abuse, and contamination. This is critical, as proppant is the primary construction material for a conductive fracture. To evaluate these supply chain issues API quality practices include long standing principles: 1) representative sampling from a flowing stream, 2) standardized testing with calibrated equipment, and 3) sample retention for follow-up evaluation. Since proppants are chosen to improve reservoir fluid recovery, evaluating quality and performance before the frac identifies deficiencies, assigns accountability, improves job design, and facilitates an opportunity for the best reservoir response. Case histories are included.

Plunger lifts are used widely to remove liquids from gas wells. The Pacemaker plunger is a new approach to this traditional method of artificial lift. Traditional plunger lifts require shut-in time for the plunger to fall and to build pressure to drive the plunger to surface. Shut-in time equates to lost production and forces liquids back into the formation. The Pacemaker normally only requires 5-10 seconds of shut-in time per cycle, and little or no pressure build-up time. The plunger operates as two interdependent pieces. Each fall separately and can do so against significant gas rates. Once on bottom, the ball scales off in a cavity in the piston. Gas velocity then drives both to surface. At the surface a rod in the lubricator separates the ball from the piston, and the next cycle begins. The end result is that the well produces continuously and liquids arc not forced hack into the formation