Sucker rods are simple in form and function, however, they operate in a sophisticated engineered system over great lengths without direct visibility. Because of this, we as engineers must do our best in predictive efforts to provide the best configuration for the highly dynamic system.
Rod string design software utilizes complex math to compute stress loading throughout the system. Design software w/ deviation included incorporates well-bore geometry to estimate ancillary loads throughout the design, i.e.: side-load & drag load from rod-on-tubing contact.
An improved method of accurately evaluating system and rod string stresses has been developed and computed. This method combines the industry standard Gibbs wave equation and trusted rod-string loading computation, taking it a bit further, evaluating the deflection behavior of the sucker rods throughout the deviated wellbores, and computing additional stresses based on arc deflection.
In instances of deviation and molded rod guides, sucker rod behavior changes dramatically. Dog-leg severity combined with most molded rod guides creates intermittent sucker rod rigidity and assumed perfect alignment with the tubing. This then causes the ability of increased bending moments and bending stresses. Fiber loading1 around the circumference of the sucker rod is then increased, leading to regions of the rod body exterior being subjected to stresses far higher than intended.
By accurately computing bending stresses and adding them to the total system loading through the deviated well bore, accuracy in the predictive system is increased, creating additional awareness to the system on a detailed, per rod level.
Despite general assumptions, stress loading is not linear throughout each sucker rod taper. This is often understood but not quantified, visualized, or addressed in string design software outputs. The effort of this paper is to provide detailed engineering awareness to rod loading, openly discussing with operators the effects of minor rod deflection and its associated stresses, and how this then encourages pre-mature fatigue fractures.
dv8 Energy and Black Mamba Rod Lift have worked together to build a web-based rod string loading fact checking system which validates and visualizes string design loading throughout the pumping cycle, addressing the bending stresses created from deviation and rod deflection in three different states: slick rod, guided rod, and under a buckling state.
Rod pump failures often times exceed the failures rates of other downhole products, such as sucker rods and tubing. The largest section of the rod pump, and most costly to replace, is the pump barrel. Barrels of all different shapes and sizes, material grades and coating options are available to the market. The available coatings have been questioned for their durability while also being limited in their applications. Chrome barrels and NiCarb surface coatings are widely available but often times cannot be used in Acid Jobs (Chrome) or in heavy abrasive environments (NiCarb). Operators often seek a barrel that can operate in Acid jobs while also providing the wear and abrasion resistance needed downhole. Exceed has pursued the task of utilizing the proven success of boron diffusion in production tubing and applying that technology to the rod pump barrels. The strict tolerances on the ID of rod pump barrels have made this an extremely difficult task leading to many companies attempting this process, only to fail. Exceed will be presenting on the 2-years' worth of field trials downhole with US Operators on these barrels, primarily in the Permian field.
Rod pumps often fail due to gas and solid interference. When the system’s check valves are unable to displace these solids or gas it can cause failure and significant damage to the overall rod pump system, such as intense ball rattling, plugged cages, inefficient pump fillage, and fluid pounding.
Historically, the industry has dealt with these issues by utilizing stellite lined and insert guided cages with alterations for the ball’s clearance. However, these offerings have only provided a linear fluid path through the restricted valve areas. By changing this fluid flow path profile, check valves can improve the valve flow coefficient and more efficiently contains gas and solids in the fluid flow path. Additionally, by optimizing the flow design and creating a shorter ball travel length, Harbison-Fischer’s HFX cage reduces gas and solid interference by lowering the pressure drop during valve actuation, improving the overall run-time and pumping efficiency.
A rod pump’s performance depends on its ability to open and close valves during production operations regardless of the well’s conditions. The HFX cage delivers a higher lifting force that maximizes pump fillage and overall performance.
This white paper aims to define the variables and understand the factors affecting the coefficient of volume (Cv) of a check valve (cage) used in rod lift applications. This understanding will help to predict the pressure losses in different pumping well conditions and help optimize the system’s valve efficiencies. Four variables will be discussed in this paper to identify an improved rod pump cage design: 1) fluid force on a ball type check valve 2) net lifting force and coefficient of lift on ball 3) fluid tracing and untracing on a ball surface 4) changes in ball resistance through the cross-sectional area. These four variables will be explained with either a general engineering equation, a finite element analysis, or a laboratory model with defined test parameters. The finite element analysis is used when general engineering formulas are unable to meet the fluid flow conditions. Similarly, the finite element analysis has few limitations to replicate actual well conditions for this study. It is critical to understand these general engineering and test analyses to understand a check valve’s efficiency & loss.
In 2015 a proprietary quenched and tempered sucker rod product line was introduced to the North American market. Field results showed a considerable improvement of reliability and performance of the two proprietary rod grades (Critical Service, CS, and High Strength, HS versions) versus previously installed rod grades. The performance and reliability of over 300 installs are tracked and used to provide input to R&D and Product Development teams to continuously improve the products with the goal of further increasing run life and performance.
In 2020, Root Cause Analysis and ultimately, Finite Element Analysis (FEA) from rod failures in Chord Energy’s wells identified specific scenarios present in deviated, high load wells in the Bakken that created loadings exceeding the simulations from industry rod lifting and string design software by a significant percentage. This was key input to understand the necessary steps to further improve the corrosion fatigue performance of the rod grades.
An extensive research and development project identified a possible continuous improvement in the form of optimized Surface Texture & Finishing (ST&F). A matrix of various Surface Texture and Finishes were performed on samples with controlled variables for corrosion fatigue testing, which was executed at an in-house laboratory and benchmarked with earlier testing. Based on these results, the next generation product was deployed to wells in the Bakken for field trials, where previous rod grades had major challenges with run life.
Finally, field data and results on run life from these field trials will be included to showcase the performance.
The workover process provides a unique opportunity to directly measure wellbore friction as the rods effectively probe out the wellbore. Measuring this effect is challenging as no sensor exists that can provide an accurate, high resolution, high frequency measurement during the entire workover process. This presentation will analyze data gathered from a custom load & position sensor placed in-line with the rod-hook during the workover process. The normal rig crew process was unaltered beyond the initial installation and removal of the sensor. Detailed sensor measurements are available for each stroke of the rig and processed to determine the overall behavior of friction acting on different lengths of rod in the hole.
Inaccurate rod string spacing on rod pumped wells may result in significant maintenance costs and well productivity issues. To avoid unnecessary pump damage and optimize pump performance, precise placement of the rod string is key. This session will explore how a dual purpose well spacing tool /rod rotator addresses the need to adjust the rod string while harnessing benefits of a rod rotator.
Rod pumping has been challenged by solids contained in produced fluids, as they reduce pump run-life. For horizontal wells solids risks have dramatically escalated, as hydraulic fracturing has exponentially increased in terms of number of stages and the amount of proppant pumped. EOR schemes can also escalate solids in produced fluids. To combat solids in the produced fluids reaching a pump, control methods have included solids separators and filtering screens. Both methods have realized limitations and therefore have not effectively resolved solids risks to acceptable levels.
Solids separators have typically been gravity and/or cyclonic based. Risk limitations with solids separators has been their ability to separate solids over broad solids particle size and flow rate ranges (a wide turn down ratio). Both cyclonic and gravity-based solids separators struggle to efficiently separate finer particles, such as 100 mesh frac sand, particularly when flow rates range from zero percent to 100 percent during a rod pump cycle. Cyclonic separators also face the reliability risk of erosion due to their inherent angular momentum solids separation design.
To effectively separate solids over a broad size and flow rate range, filtering is required. Risk limitations with solids filtering include filter screen plugging (from solids and scale) and from erosion. Eventually all filtering screens will plug off if flows are in the same or in one direction. For example, if flows are always in one direction, there is no place to contain the filtered solids other than on the filter screen itself. Running more filter screens for more filter screen surface area can extend the run life before plugging, but cost economics quickly come into play. Installing a filter screen bypass, for if in the event it becomes plugged, just exposes the pump to damaging solids once again. Solids can cause erosion, so filter screen designs need to minimize fluid velocities and use erosion resistant materials, which can escalate costs. Scale risks must also be controlled by designing for very low-pressure loss and drops through the filter screen and likely in combination with chemical treating – this means that filter screens placed upstream of a gas separator will likely be ineffective for preventing scale deposition due the expected high multiphase flow velocities.
A downhole self-cleaning filter system was developed to resolve these risk limitations. Proven surface facility self-cleaning filter screen system technology was re-designed to be deployed downhole.
The engineered system components were as follows:
• a filter screen engineered to hold and release solids down to 120 micron particle size; solids do not get retained in or on filter screen when fluid flow ceases during the pump’s downstroke,
• placement of the filter screen sequentially after the gas separation stage and inside the uppermost mud joint – in this location, solids laden liquid’s flow path U-turns from downwards to upwards through the filter screen and allows solids to be contained out of harms way into standard mud joints,
• continuous self-cleaning of the filter screen is achieved with a specially designed rod pump with a standing valve that back flushes the filter screen each pump stroke – a reverse pressure pulse wave and a back flush liquid volume each pump stroke dislodges solids from the filter screen and settles them downward into mud joints during the pump’s downstroke, and
• the filter screen is open-ended for allowing bypass in the event of filter plugging.
Field trials have recently been implemented with early time promising results for extending pump run life. The concept, design, field implementation and results will be shared.
Rod pumping horizontal wells is more complicated and challenging than for vertical wells. For system reliability reasons, it is common for horizontal wells to have a rod pump placed in the vertical section above the wellbore’s curve, which limits drawdown. This means the pump is placed a vertical distance above the producing zone and a pressure gradient of fluid between the pump and the producing zone exists. This pressure gradient can add 200- 500 psi of back pressure to the producing zone, limiting drawdown.
Drawdown is also limited by multiphase flows emanating from the horizontal wellbore that are inconsistent and sluggy. Flow regimes and inconsistent flow slugging tendencies are different in the horizontal, curve and vertical sections of the wellbore and these sections can compound each other for a bad unmanageable slugging condition at the pump’s location. Such inconsistent flows make efficient downhole pump gas separation very challenging. Consequently, a troublesome fluid level in annulus above the pump often remains. This fluid level can add an additional 200-500 psi of back pressure to the producing zone, further limiting drawdown.
To resolve these drawdown limitations and to therefore maximize drawdown, the pump would need to be lowered down into the curve section of a horizontal well. This presents several reliability risks, including:
• reduced run life with increased wear on the pump, rods and tubing,
• increased costs for surface pumping equipment and rod string due to increase loadings,
• reduced downhole gas separation efficiency at high wellbore inclinations, and
• reduce rod pump performance with valves not opening and closing efficiently at high inclinations.
Engineering a rod pumping system to operate at high inclinations reliably around the wellbore’s curve was undertaken. Field implemented has demonstrated a high success rate for dramatically increasing production and achieving good slugging conditions, while not realizing an increase in failure frequency. Results will be reviewed and shared.
To deal with gas and sand problems in their conversion and rod pump wells an operator company in south Texas started introducing a combined technology of two-stages filtration with a modified poor boy gas separator obtaining excellent results. This paper explains the technology used and shares the information used to design the tools and the results achieved in the first wells completed. The screening process to choose the best technology started by trying different technologies for gas and sand control below the rod pump. Different technologies were revised sharing data like sand particle size, pump design, fluid production expected, and wellbore configuration to get the best design from different companies. The technical and economic evaluation determined the combined system with two-stage filtration and gas separation was the best technology among all the installations. The results were spread to other wells changing the configuration based on the well conditions but maintaining the same principle of operation. After the installation of this technology in each well, it was clear a substantial increase in production among the wells that was caused for the improvement in the pump cards after the installation. The downhole equipment has been able to handle better gas production and no sand problems have been reported so far. The success of this technology has extended the operational capabilities of the pumps allowing the engineers to operate better their wells. Pump cards before and after the installations are summarized in the presentation to show evidence of the good results obtained.
After the wells are converted from ESP to rod pump or when the gas represents an issue in the rod pumped wells, the production engineers are limited in the drawdown and the production they can get out of the wells. We are presenting an alternative for the operators to optimize the production's BHA and overcome sand and gas problems that limit the ability to increase the income of the oil fields.
We present a survey of uses for distributed fiber optic sensors (DFOS) in oilfield production and operations. Downhole DFOS measurements of temperature, strain, and noise along the entire length of the wellbore serve as diagnostic tools for flow profiling and artificial lift monitoring. Field cases demonstrate DFOS abilities such as identifying gas lift injection points, quantifying stimulation volumes injected into multiple perforations, and providing actionable insights on paraffin challenges. Future applications of DFOS measurements for artificial lift diagnostics are proposed.
The Permian Basin is well known for multiple remunerative producing zones. Recent development from the Delaware Basin has presented a need for economical chemical selections. Chemical treatment strategies applied in contemporaneous formations in the Midland Basin may not result in an optimized solids risk mitigation approach for the New Mexico Delaware Basin. Having the right treatment strategy in place is essential in preventing failures and downtime due to under deposit corrosion, microbiologically influenced corrosion (MIC), plugging and emulsion issues. Most operators have a firm understanding of localized problem facilities and well sets but have a less defined macroscopic perspective needed to minimize risk in terms of geography, geology and water chemistry.
This paper highlights a tailored chemical treatment strategy developed for solid mitigation for a Delaware Basin operator. Over 200 New Mexico and Texas State line Delaware Basin solid samples were collected over a two-year period, spanning 7 distinct producing intervals. Focus was placed on the most common producing zones such as the Wolfcamp, Bone Springs and Avalon formations. A statistical approach was taken to break down which formations have the greatest potential for paraffin, carbonate, acid soluble iron compounds and sulfate scales.
Trends in the data suggested certain formations are more prone to certain types of solid precipitation. The data is in line with field observations across the Northern half of the Delaware Basin. Tying solid deposition history on a formational level helped the customer understand where treatment was no longer needed, where it was still required and where it may be needed in the future.
The trends provide a proactive road map for risk mitigation and treatment optimization before a solid deposition event has occurred. An understanding of these trends have potential to save operators downtime and additional financial burdens associated with work over costs and deferred production in the Northern half of the Delaware Basin. A similar macroscopic approach in other basins may be applied to identify what proactive treatment strategies could be developed based upon the unique challenges of those regions and similarly improve field performance.
Gradual diminution of the flow path of hydrocarbon in the near-wellbore area is heavily linked to formation damage accumulation and well productivity reduction. Organic deposition in the formation and well bore area can result from the use of hydrochloric acid (HCl) during acidizing, especially in the presence of free iron, addition of organic liquids such as diesel, kerosene, or gasoline and the use of CO2 injection for EOR projects. Laboratory evaluation of the nature of the crude oil and stimulation fluids indicates the potential severity of the problem.
The usage of organic and inorganic acids for inorganic deposits removal like calcium carbonate and iron sulfide has become one of the most used methods for well clean-up and stimulation. Unfortunately, due to the nature of the produced fluids, organic deposits like paraffin are coating the inorganic scale, minimizing the performance of the acid job. Typical aromatic solvents utilized to address the organic deposits are not highly effective, as they cannot be fully miscible in the volume of the acid, and they only dissolve a specific weight of paraffin based upon the molecular weight of the wax, temperature, and pressure before the solvent’s power is exhausted.
A multipackage formulation has been developed, to be fully miscible in acid, maximizing the performance of the scale dissolution, by effectively de-oiling and penetrating the organic coating layer build-up on calcium carbonate and iron sulfide scales in shorter soaking periods. This novel formulation cleans spontaneously by diffusion, breaking and solubilizing the organic deposits and providing the following additional benefits:
• Water-wets the surfaces (formation, downhole equipment, tubing, and flowlines), including paraffin particles, preventing the re-agglomeration further down in the system
• Improves formation oil mobility by reducing the capillary pressure in the formation
• Prevents emulsion creation and acid sludge formation during acid jobs
The work in this paper studies the effect of this novel chemistry when it is used in acid jobs, and presents case history information on testing, chemical application, and subsequent field results across the Permian Basin in conventional and unconventional production.
This paper will cover multiple trials of a new combination of advanced gas and sand separation techniques which have now proven to consistently perform at an exceptional level which was previously unobtainable. Details of the performance will be thoroughly outlined. The assembly is designed to be very rugged, simple to run, and easily economical.
In mature oil fields, the success of gel treatment results depends on the ability of the gel to reduce the high permeable formation without damaging to low permeable formation. Formation damage refers to the extent of damage reservoir rocks face from various drilling techniques and/or chemical treatment during well completion. A dynamic filtration test was used to investigate this effect using distinct core samples, brine concentrations and preformed particle gels. The effect of high pressures applied on the particle gels on various core samples with various permeability ranges was determined. These gels were pushed into the core holder with samples and the core permeability change was calculated. Different constant pressures were used to push the piston behind the gel samples. Then, the gel was flown around the core sample and collected in the outlet container. Various hardware was used to tighten the apparatus and provide connection between brine source, syringe pump, piston accumulator, core holder, and flow outlet container. The damage on the core was evaluated by comparing the original core permeability and the core permeability after gel treatments. Pressure gauges were used to measure the pressure drop across the core samples. The penetration of the particle gels into the low permeable formations can be decreased by the best selection of gel types, particle sizes, and brine concentrations under the reservoir condition. This work results can be used to select the best gel types for the right reservoir condition such as reservoir permeability, and reservoir pressure.
Being able to calculate and predict the inflow performance from a well is critical in designing any form of artificial lift. The production/lift capability of whatever form of artificial lift chosen should closely match the current and future inflow performance of the well for the economics of the investment to be the highest.
Inflow performance estimation is also required to ensure that production is being optimized. When used with the outflow performance of the lift method, NODAL analysis can be performed to evaluate the entire production system for production enhancements.
This paper discusses the various methods available to determine the inflow performance of a well from the reservoir to the wellbore. The methods include the Productivity Index, Vogel Inflow Performance Relationship and Fetkovich method. In addition, methods to determine the inflow performance when the reservoir pressure is not known and predicting inflow performance over time are discussed.
One of the most expensive issues while workover operations are fishing and sometimes it ended up being a non-successful operation when the fish is left in the hole. The time expended trying to pull a fish in horizontal wells is particularly long and the costs are high. Proper planning and good practices should reduce the risk associated with this problem but as a contingency, a new tool has been incorporated in more than 150 installations in the Midland and Delaware basin during 2022. The tool was installed below the weakest point of the BHA or at the end of the tubing and its purpose is to catch the BHA at the TOL avoiding the fish to land in the curve or horizontal section of the wellbore. Once, the fish is maintained above the top of the liner and at the same time allows fluid flow around it, the fishing becomes an easier operation. Two case studies in the same field are presented where one well was installed with this new catcher and the fish was recovered in 3 days. On the other hand, the second well did not have a catcher and the company expended more than two months trying to pull the fish and in the end, they couldn’t recover it. This well had expenses of more than 1 million dollars without counting equipment expenses.
Tubing leaks account for half of the failures in the Bakken wells. The root cause is coupling on tubing wear due to the non-metallic guides wearing out.
In order to combat this problem, ToughMet 3 TS95 sucker rod couplings were installed in up to 250 wells to significantly reduce the failure rate in the field. Several individual case histories will be discussed to demonstrate the lifetime extension and reduced wear rates seen with the use of the new couplings.
Additional benefits have been observed, particularly increased fluid production, increased pump fillage, higher Fluid loads, and lower gearbox loads. XSPOC data will be presented for several wells to demonstrate the positive effects observed in the field.
Sucker rod pump or “rod pump” is a common method of artificial lift for oil and gas wells in the United States. For decades well analysts and production engineers have looked at surface and downhole dynamometer cards to diagnose various downhole and surface equipment issues alike. In more recent years, helpful rod pump diagnostic tools have aided well analysts and production engineers in training and the analysis of downhole dynamometers utilizing generalized libraries with known behavior for downhole dynamometer cards. Unfortunately, the same generalized libraries do not exist for surface dynamometer cards limiting these tools to base their diagnostics solely on information captured in the downhole dynamometer card. Although a majority of data used for analytics and diagnostics can be found in the downhole dynamometer card, it has been known for years that still more helpful analysis can be done utilizing data and patterns found in the surface dynamometer card. Recently, strides have been made in software tools to analyze data and patterns not only found in downhole dynamometer cards, but also the surface dynamometer card. It has been well known within groups with expertise on dynamometer card analysis that pump tagging and shallow friction can be seen more obviously in the surface dynamometer card than the downhole dynamometer card. Mimicking the thought process of these experts, algorithms leveraging data science tools and statistical methods have been implemented in diagnostic software tools that can better detect both shallow friction and pump tagging problems that can be seen in the surface dynamometer card well before they are seen in the downhole dynamometer card, especially for deep wells. These new algorithms will be yet another tool in the continual aid of well analysts and production engineers to more quickly and effectively analyze dynamometer cards and optimize production for the sucker rod pumping system. Although current downhole analytical software provides great benefits to users, including these algorithms allows for a more robust and effective dynamometer card analysis and diagnostics software.
Gas and sand interference remain one of the most common challenges in the vast majority of wells in the Permian Basin. Gas interference can lead to poor pump efficiency and severe sand issues can lead to sticking and excessive wear and tear to the pump – both of which lead to unnecessary operational expenses and even well failure. Recognizing the ineffectiveness and shortcomings of current models of gas and sand separator systems and other mitigation technologies, WellWorx set out to design a more effective system to combat the dual issues in rod pump wells. In the first stage, fluids enter the sand separator and solids are removed using a dual-channel spiral system before forcing solids into a three-foot sand drain that maximizes the distance between pump intake and solids discharge. In the second stage, the gas separator creates the greatest tool OD to casing ID ratio possible, allowing operators to maximize the annulus of the given well bore. By increasing the size of the annulus, it decreases the downward fluid velocity of the fluid prior to pump entry, allowing gas to escape up the casing. Installing this type of equipment could potentially allow operators to stay in higher production longer and give more freedom in pumping practices with or without lowering the pump in the curve, all of which raise profitability. This paper presents the technology behind this combination gas and sand separation system and offers case study results that proves the positive impact of this tool on overall operating expense.
Rod pump service data provides valuable insight into wellbore conditions and the efficacy of the rod lift system. Trend analysis of metrics such as reason for well pull and pump component evaluation provides increased visibility about individual well performance issues and more broadly, about field performance. Comprehensive pump service data is an indispensable supplement to an operator’s internal data in well review meetings for the purpose of improving optimization efforts. This paper will focus primarily on how this data may be used to benefit two key factors: performance and design.
During the hydraulic fracturing age, hydraulic jet pumps have seen an increase of installation numbers across the most prolific unconventional well fields in the United States of America, as well as in overseas oil and gas fields. Its simplicity, reliability, robustness, and adaptability have made the jet pump one of the known artificial lift systems on the production of unconventional wells, specially on the early stage of production. During this stage production rates are high, and solids (proppant) are produced; this can be a challenging combination to deal with. When correctly operated, jet pumps can be a useful and effective solution for this unconventional well production cases. Jet pumps can and it have been used to continue to produce an unconventional well through its producing life to depletion, until a transition to a different method is needed, mainly because of the minimum required pump intake pressure that a jet pump needs to operate. Jet pumps require a minimum suction pressure to function, otherwise a phenomenon called “power fluid cavitation” or “low intake pressure cavitation” will occur. When the down-hole pressure of an unconventional well that is operated with jet pump declines to lower levels, specific operating and optimization strategies have to be implemented, in order to maintain acceptable production rate levels, and to optimized the usage of the available surface equipment capacity. During the late stage of production of an unconventional well , a successfully operated jet pump strategy includes several good practices that include: Well completion configuration, surface equipment selection, suction and discharge piping, production data processing and analysis, nozzle and mixing tube resizing and power fluid pressure schedule. The correct application of the previously mentioned actions, increase the possibilities to approach to a trouble free operation, and to a continuous jet pump system implementation from its installation, on the early production stage, to a point where the well flowing pressure is too low that a change of system is required, to a low rate – low pressure production system. This paper presents a straightforward discussion on the operation of jet pump systems during the late production stage of unconventional wells, recommended practices, troubleshooting and procedures to keep the well producing, even when the pump intake pressures are relatively low.
There are thousands of marginal wells in the Permian Basin with potential to produce significantly more oil and gas with the assistance of plunger lift. Working with multiple operators in the Permian Basin, PLSI has installed plunger lift systems in these type wells and realized significant increases in oil and gas production. The common characteristic is fluid downhole which never makes it to the surface production facilities. This fluid loads up the wellbore downhole which increases hydrostatic back pressure on the formation that holds back production. By installing a plunger lift system, we have seen wells that were producing a few barrels of fluid per day double oil or gas production. This paper will present production data from operators showing increases in production and revenue with minimum expense that resulted in significant increases in net operating income.
Deviated wellbores, whether intentional or unintentionally drilled, are becoming ever more common. Rod-on-tubing friction occurs as a result of these wellbore deviations. This friction has a detrimental effect on the longevity of the equipment through accelerated mechanical wear. Downhole friction can also obscure analysis and optimization as the friction distorts the calculated downhole conditions. The only methodology currently available to account for this wellbore friction is through by way of a wellbore deviation survey. Deviation surveys have varying degrees of resolution, from coarse 100+ foot surveys during drilling, to high resolution gyro surveys which can resolve one foot or better along the wellbore length. Geometry derived from the deviation survey is then used to infer points of contact along the sucker rods, and in conjunction with the wave equation methodology, tensile and side loads are determined. These are idealized calculated values because the geometry is indirectly measured, and contact points are not exactly known or understood. The work presented here attempts to directly measure friction along the wellbore. Two fundamentally similar approaches are discussed. The first utilizes an instrumented rod-hook to measure load and position during a workover. Wave equation methods are then applied for each ?stroke? of the rods by the workover rig while pulling rods out of the hole to determine dynamics along the remaining section of rods in the wellbore. A friction map can then be computed over the entire length of the wellbore as rod sections are installed or removed. A second approach utilizes a downhole tool that is run on the sandline or wireline. A section of weight-bars of a desired length below (and possibly above) the tool provides an opportunity for friction to act during the trip out of the hole through the wellbore. Correlating loads measured by the tool with position along the wellbore, and eliminating dynamic forces due to acceleration, provides a directly measured friction map of the wellbore at or near the points of friction. Both approaches require little additional interaction from surface personnel as the work necessary to gather the data is already performed. All that is needed is to capture and process the data from those existing operations.
Horizontal drilling and the need for effective completion techniques has given birth to a wide variety of solutions in North American oil and gas plays. For many operators, it has become a top priority to optimize proppant distribution using buoyancy enhancer additives and to achieve fracture diversion with clean solutions that do not require intervention. At the heart of these initiatives is the Permian Basin, which is being revitalized through the use of intelligent completion technologies to make those priorities a reality.
This paper proposes two solutions that can be customized for an integrated fluid system that helps improve proppant distribution, deepen proppant penetration within the complex fracture network, increase proppant pack volume, and increase maximum proppant concentration that can be placed. By improving proppant placement and increasing the fracture volume occupied by proppant, operators can enhance conductivity of the fracture network, resulting in improvements to initial and long-term production.
Unconventional wells are drilled in shale formations to produce oil and gas utilizing horizontal drilling and hydraulic fracturing. Many think fracturing creates a ‘rubble zone’ around the wellbore allowing the free oil and gas to be produced.
Unconventional wells are generally drilled “vertical” and then “kicked-off”, building the curve and then continuing to drill horizontally at a targeted distance through the layer of oil-bearing rock. Due to the intentional and unintentional dogleg severity that occurs throughout the drilling process, extreme side loading conditions are created when rod pumping. S curve wells are common unconventional wellbore trajectories that present challenges when rod pumping.
Due to the rock properties of shale formations, wells with long laterals through the pay zone are completed. This results in large production volumes with exponential decline. As these wells begin to decline, artificial lift is needed to continue to effectively lift fluid to the surface. Rod pumping is usually the preferred artificial lift method for liquid rich wells.
This paper focuses on the sucker rod string as it delivers the energy created at surface to the downhole pump. The sucker rod string typically consists of steel sucker rods, connected by couplings every 25 feet, to mechanically lift the fluid from the downhole pump.
Unfortunately, the complex trajectories of unconventional wells create mechanical friction between the rods and tubing resulting in extreme side loading conditions. This leads to rod parts or tubing leaks from extensive wear of the contact area between the couplings/rods and tubing. The force or side load is often concentrated on conventional rod’s couplings, increasing the pressure between the rod and tubing string. This leads to an increase in failure rates.
Continuous rod is a viable solution for deviated wells because of the lack of couplings, the side load is distributed over an increased area of contact. This results in longer run times.
This paper presents results from five high failure rate wells that were converted from conventional sucker rod to continuous rod due to failures caused by downhole deviation.