Leveraging advancements in material science, a comprehensive pilot study of the effectiveness of vibrational-energy tools to inhibit asphaltene and paraffin was conducted involving over 40 wells throughout the Permian Basin, encompassing both conventional and unconventional reservoirs. This technical paper provides an in-depth analysis of the tool, which operates on the interaction of specially formulated solid materials that passively emit vibrational energy at targeted frequencies. This energy alters the physical behavior of hydrocarbon molecules, producing lasting changes in fluid properties.
Raman spectrometry provides solid, quantitative proof for how these modifications work, backing up the scientific foundation of the tool. The vibrational energy it creates interferes with the van der Waals forces that normally cause paraffin to clump together, which helps keep hydrocarbons stable right at the source. In addition, this resonant energy not only helps prevent further aggregation but also lowers viscosity and density. It also makes it easier to separate oil and water by reducing their interfacial tension. Altogether, these effects lead to more efficient production.
For the pilot, comprehensive candidate well selection criteria were established. The chosen wells were systematically excluded from all existing chemical treatment regimens targeting paraffin and asphaltenes. This case study presents empirical evidence of the tool’s performance, utilizing production metrics and operational monitoring data to demonstrate its effectiveness. The findings illustrate the tool's ability to significantly reduce chemical spend, extend operational runtime in wells historically susceptible to solids-related issues, and achieve substantial production uplift.
 

For decades, VRUs have been deployed as compliance equipment and treated as commodity hardware – sized on rough estimates, lightly engineered, and minimally monitored. The results have been predictable: inconsistent runtime, chronic loading instability, ever-increasing maintenance costs, and a long-standing belief that VRUs simply “don’t work.” This paper examines why that legacy persists and outlines a modern engineering and measurement framework that significantly changes VRU performance, economics, and reliability.

The approach centers on precise sizing, real-time operational data, and flexible deployment strategies designed to match dynamic vapor loads. A comprehensive operational dataset – including pressures, temperatures, load signatures, runtime behavior, oil level, and measured vapor flow – enables predictive maintenance, drift detection, and stable runtime across a wider range of operating conditions. Rather than relying on a single indicator, this data ecosystem provides the analytical foundation for a proactive VRU program. The same infrastructure also supports accurate emissions accounting, turning VRUs into valuable compliance assets as regulators move toward measurement-based methane reporting and as operators work to reduce the significant financial exposure tied to modern methane enforcement.

Field deployments in the Permian Basin show significant improvements in uptime, maintenance cost, and equipment longevity, with operators experiencing fewer cycling events, reduced downtime, and lower LOE. These results indicate that a measurement-driven VRU program can prevent both oversized and vapor-constrained installations, significantly reducing risk while improving economic return.

This paper will present the engineering principles, measurement insights, and early field learnings behind this next-generation approach – and why solving the long-standing VRU problem ultimately turns vapor recovery from a perceived liability into a measurable, high-value asset.

While the west Texas natural gas industry has been on life support since 2008 with low prices and inadequate takeaway capacity it is on the verge of a major revival in order to meet upcoming major LNG and data center demand increases.   These plants and data centers will require 18-24 BCFD of incremental supply over current levels in the US by 2030.  Based on EIA projections it is expected that the Permian will provide up to 45% of this incremental demand.  For the first time since 2018 West Texas pipeline investors saw this demand coming well in advance and are responding in force to put in enough takeaway capacity to help meet the need for incremental production.  The expected additions to the Waha system in 2026 are staggering with 6.6 BCFD of additional takeaway capacity increasing to over 10 BCFD by 2028.  On the supply side the latest expected incremental supply growth from West Texas is less than 1.4 BCFD in 2026 and 0.6 BCFD in 2027 and 2028.   When this is combined with an expected 32 GW of incremental demand from Texas data centers alone by 2028 the demand for gas looks pretty strong.  Each GW of generating capacity requires 160 MMCFD of feed gas for the turbines or an incremental 5.1 BCF of demand by 2028 that will not be heading to the LNG plants.  Between the newly added capacity expansions and huge expected demand growth West Texas gas has the potential to be the next $100 oil at a time when oil prices are struggling to stay above $60.  At a minimum Waha should be on par or better than Henry Hub which was the case prior to the capacity bottleneck pricing disaster of 2018-2026.  With virtually zero drilling and recompletion activity in Permian basin dry gas reservoirs since 2008 this represents a major ramp up of gas production from legacy fields that have had little or no activity for the last 18 years.  The bulk of the current expected increase comes from associated gas from horizontal oil wells which is the most of the 1.4 BCFD expected 2026 West Texas supply growth expectation.  Significant volumes of incremental gas supply from dedicated gas wells must be added to meet the expected demand growth without focusing on dedicated gas wells.  The oil focused shales in the Permian would need a significant increase in rig and frac crew count to meet this demand with oil well associated gas alone.   Prior to the price spikes from the Iran conflict the EIA was forecasting +/- $55 oil in 2026.  Once this temporary increase in prices ends it is unlikely that this will forecast change significantly.  Without a significant sustained increase in oil prices the oil focused rig and frac crew count will not follow and thus significant additional supply is probably not going to come from associated gas.  The bulk of the incremental gas must come from 100% gas producing wells in the Permian Basin.   

With an estimated 46,000 producing horizontal wells in the Permian Basin currently yielding less than 200 BOPD, operators are facing a growing inventory of declining wells. This base production decline must be continually offset by new well additions—an increasingly costly and resource-intensive strategy. As a result, the industry is experiencing a resurgence of acidizing treatments in horizontal wells as a means to restore productivity and extend asset life.

Transitioning from traditional acid treatments applied to short vertical pay zones to long horizontal laterals introduces new complexities in treatment design and execution. Achieving consistent production uplift and sustained well performance requires innovation across multiple technical dimensions. Advances have emerged in candidate selection methodologies, surfactant chemistry, diversion techniques, equipment design, stage optimization, and scale management practices following acid stimulation.

This paper presents the latest strategies and innovations driving the effective revitalization of horizontal wells through acid stimulation. Emphasis is placed on integrating modern chemical systems, operational best practices, and field-proven designs to maximize production gains while maintaining long-term well integrity.

The Resin-in-Cement (RIC) system is a hybrid technology that merges thermosetting epoxy resin emulsions with traditional Portland cement systems, creating a stable emulsion for superior wellbore sealing and bond-adhesion in oil and gas wells. It solves key integrity issues like micro-annuli , and debonding in harsh downhole conditions. Conventional resin-cement mixes often fail due to density-driven separation, causing incompatibility and a non-homogeneous slurry. RIC counters this with proprietary chemistry of dry and liquid additives, ensuring uniform resin dispersion, additive compatibility, and strong adhesion to casing and formations.
RIC excels over traditional cement in flexibility and durability. Portland cement is economical but rigid—high Young's modulus, low toughness, moderate bonds, and permeable set cement sheath—leading to stress-induced cracks. RIC cuts Young's modulus while boosting flexibility against temperature, pressure, and mechanical loads. The RIC system shows an increase in modulus of toughness against conventional cement blends, absorbing energy to resist fracture. In cyclic pressure wells such as injection wells, it adapts to expansions/contractions, preventing fatigue cracks and prolonging life. In mobile formations such as highly mobile salts, lower stiffness allows elastic deformation, easing shear stress and avoiding debonding or isolation failures. Shear bonding to casing and formation shows formidable adhesion, curbing migration; permeability falls, compressive strength rises, fluid loss drops, and free fluid is non-existent. Typical temperature profile of this system can range from Surface ambient to 200oF+, and density of the systems can be run from a conventional 10 ppg up to a heavyweight 18 ppg slurry.
Economically, RIC delivers resin's premium traits—impermeability, resilience—through bulk cement, using 15-30% resin to cut costs dramatically versus pure resin. This system is ideal for P&A, HPHT wells, and injection applications.
Ultimately, RIC transforms zonal isolation: cement strength plus resin agility, affordably, for enduring well integrity.

This study investigates the feasibility of repurposing produced water as an electrochemically active medium for energy recovery, reframing it as a resource rather than a waste product. An electrochemical “mud battery” system was developed using a semi-solid mixture of produced water and clay-rich soil. The clay matrix provides structural stability while maintaining ionic conductivity, enabling sustained electrochemical interactions. Anode and cathode electrodes were embedded directly into the produced-water mud to maximize electrode–electrolyte contact and minimize system complexity. External load resistors spanning a range of resistance values were connected across the electrodes to evaluate performance under varying electrical loads. For each load condition, voltage measurements were recorded across both the mud medium and the external resistor. These data were used to calculate current output and construct voltage–current (V–I) characteristic curves, enabling analysis of system behavior and electrochemical efficiency. Results demonstrate measurable and repeatable electrochemical activity within the produced-water mud matrix. Although power output remains limited, the system shows potential for low-power energy recovery applications.

Modern unconventional wells increasingly rely on gas lift compression, representing ~30% of initial artificial lift systems in the Midland Basin and ~40% in the Delaware Basin by 2024. Permian produced gas is often liquid-rich, containing higher propane and butane concentrations and specific gravities typically ranging from 0.72–0.79 (and occasionally up to ~0.97), forcing compressors to operate near phase boundaries. Temperature changes during staged compression can cause liquid dropout, contributing to downtime. Multi-year field data shows 53% of shutdowns result from process upsets and gas conditions rather than mechanical failure. Elevated discharge pressures and cold ambient temperatures further increase hydrate formation risk, making phase behavior the primary driver of compressor instability. These findings demonstrate that pressure- and temperature-driven phase behavior is the primary driver of gas lift compressor downtime, highlighting the importance of understanding fluid properties and operating conditions to improve compressor reliability.

Multiphase flow meters (MPFMs) are transforming well surveillance by enabling continuous, real-time measurement of oil, water, and gas flow without the need for large test separators. This work reviews the physics and field performance of dominant MPFM's, particularly the Venturi differential-pressure and dual-energy gamma densitometry combination, and compares their validated operating envelopes, accuracy, and limitations against conventional test separators.

Sinker bars and sinker rods are both used as methods to help maintain tensile strength and minimize buckling of the rod string in rod pumped wells. They have different applications but primarily attempt to solve the same problem. This presentation will look to assess the advantages and disadvantages of using sinker rods vs sinker bars in horizontal rod pumped wells. 

This study investigates the short-term pressure integrity and cyclic fatigue performance of transparent Cellulose Acetate Butyrate (CAB) piping designed for multiphase (gas–liquid) flow visualization under moderate pressure conditions. The experimental setup included a horizontal 3-inch CAB pipe segment coupled with a steel upstream section via pressure-rated Victaulic mechanical fittings. The system was hydrostatically tested and subjected to cyclic pressure loading between 50 and 400 psi for eight hours, simulating the conditions of a gas-lift production line operating at 500–600 psi. The primary objectives were to assess leak tightness, burst pressure, and fatigue resistance, and to evaluate the feasibility of CAB as a transparent alternative to opaque metallic or composite pipes. Results showed stable structural performance under repeated cycles with no observed leakage or deformation within the test window. CAB’s behavior under pressure confirmed its applicability for visual diagnostics and flow experiments when operated within its allowable stress limits and protected from ultraviolet exposure. Recommendations for fitting selection, testing protocol, and future long-term cyclic fatigue assessments are provided.

Produced-water (PW) management in the Permian Basin faces tightening injection constraints, induced seismicity concerns, and volatile saltwater-disposal (SWD) costs. At the same time, chemistry-rich PW contains dissolved constituents (e.g., Li, B, Sr) that may be valorized i SWD f recovery performance and market conditions support favorable techno-economics. Here, we develop an integrated decision-support framework that couples (i) chemistry-informed surrogate models for unit-process performance (recovery, effluent quality, energy/chemical intensity) with (ii) a network-based allocation model that routes PW from sources through pretreatment, optional treatment and miner-al-recovery modules (e.g., desalination and direct lithium extraction), and end-use nodes (beneficial reuse, hydraulic fracturing reuse, mineral recovery/valorization, or Class II disposal). This is a screening-level demonstration using publicly available chemistry percentiles and representative pilot-reported performance windows; it is not a site-specific facility design or a bankable TEA for a particular operator. The optimization is posed as a tri-objective problem—maximize expected net present value, minimize SWD, and minimize an injection-risk proxy—subject to mass-balance, capacity, quality, and regu-latory constraints. Uncertainty in commodity prices, recovery fractions, and operating costs is propagated via Monte-Carlo scenario sampling, yielding PARETO-efficient portfolios that quantify trade-offs between profitability and risk mitigation. Using PW chemistry percentiles reported by the Texas Produced Water Consortium for the Delaware and Midland Basins, we derive screening-level break-even lithium concentrations and illustrate how lithium-carbonate-equivalent price and recovery govern the extent to which mineral revenue can offset SWD expenditures. Comparative brine benchmarks (Smackover Formation and Salton Sea geothermal systems) contextualize the Permian’s generally lower-Li PW and highlight transferability of the workflow across brine types. The proposed framework provides a transparent, extensible basis for design-matrix planning under evolving injection limits, enabling risk-aware PW management strategies that reduce disposal dependence while improving water resilience.

Artificial lift optimization in marginal horizontal wells is often limited by gas interference and inefficient pump intake placement. Particularly in mature reservoirs producing below bubble point. As free gas evolves in the lateral, stratified flow conditions can reduce pump fillage and restrict drawdown in rod lift systems. This study presents a field case from a marginal horizontal well operated by A.C.T. Operating Company in Cochran County, Texas, evaluating the impact of the insert pump placement and intake gas separation on production performance. The well was converted from electric submersible pump to rod lift with the insert pump initially positioned in the vertical section to minimize mechanical risk. Field optimization later repositioned the pump deeper into the tangent section and incorporated intake gas separation, increasing total fluids production from approximately 358 to 560 BFPD while nearly doubling oil cut. Based on these results, a conceptual bottomhole assembly is proposed that integrates a lateral gas separation tool with a spring assisted standing valve to reduce liquid fallback and improve pump fillage. Inflow performance modeling indicates that reducing bottomhole flowing pressure to approximately 50 psi could increase oil production to nearly 20 BOPD, representing a potential incremental gain of approximately 6 BOPD. The proposed design will be evaluated through laboratory modeling and future field testing.

Development of AI controllers has allowed abnormal pumping conditions to be accurately identified remotely. Due to the geometry of most rod lifting systems corrective actions need to be undertaken manually at the well location. This paper introduces an automated approach to implementing corrective actions with the use of a non-fixed stroke length rod pumping system. The focus includes case studies where manipulating the stroke length is used to rectify the abnormal pumping condition without the use of additional equipment or service rig intervention.

The method is derived from the experience of field operators who manually manipulate stroke lengths onsite with external lifting equipment or service rigs to rectify the abnormal pumping conditions. Procedures have now been implemented for operators to utilize the non fixed stroke length capabilities of the surface pumping unit to eliminate the need for a service rig or additional equipment. Case studies focus on spacing rods, tagging pumps, freeing stuck pumps and avoiding damaged sections of the downhole pump without the use of additional equipment. Preprogrammed solutions can now be implemented to automate the process and avoid the requirement for human intervention completely.

In each case study the abnormal pumping condition was rectified through manipulation of the stroke length. Wells report a significant reduction in downtime and lost production due to immediate correction of the abnormal pumping conditions. AI POCs coupled with variable stroke length allow automated sequence solutions to be implemented for identifiable abnormal conditions. The geometry of most surface rod pumping units significantly reduce the capability of AI POCs to implement corrective actions autonomously. This technology allows the PLC to bridge the gap from AI identification of abnormal pumping conditions and implementing the corrective actions needed to rectify the condition.

As industry moves further towards AI control it is important to emphasize the mechanical limitations of the surface equipment. Powerful AI programs without the ability to implement solutions erode the value of the AI technology. When designing wells or selecting artificial lift systems it is important to consider the overall efficiency of the system, specifically whether we are limiting the AI with the mechanical geometry of the surface unit.

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.
 

Failure meetings are a proven optimization tool to reduce failures, cut costs, and increase production. However, many companies don’t utilize this tool or don’t properly optimize it. This paper will cover the basics of preparing for and holding a failure meeting along with a brief explanation of root cause analysis.  

In sucker rod pumps, accurate downhole data is necessary for control and optimization of wells and assets. Downhole data is calculated from data measured at the surface. 
In the 1990s, Sandia National Laboratory was contracted to conduct a series of tests using downhole dynamometer tools on vertical wells. This data validated the use of the wave equation and gave rise to most of the models and programs used today. In today’s Oil & Gas world, where a great majority of wells are deviated, operators have difficulty controlling and designing their wells due to inaccurate downhole data and key parameters.
This presentation will focus on comparing the conditions and equations relating to vertical and deviated wells. In a first step, the vertical case will be studied, and the wave equation derived. Challenges to using the wave equation and therefore shortcomings of today’s methods will be discussed. In a second step, the deviated case will be explored and compared to the vertical case. 
 

In the reciprocating rod lift system, the sucker rods are subjected to cyclic stresses during service which accumulate leading to fatigue failures. It is well known that the shot peen process increases the fatigue life on metal parts; with respect to sucker rods several manufacturers claim to have implemented shot peening in their manufacturing process for years. To achieve optimal parameters which yield a dramatic increase in fatigue life requires extensive studies on both input parameters and comparative fatigue testing. This paper will discuss the steps and challenges involved in achieving the optimized shot peen process and benefits on the sucker rod fatigue life. Process inputs such as shot size, shot metallurgy, shot velocity, the volume of shot and peening time was studied and evaluated by an axial fatigue test which replicated downhole loading condition. The laboratory test results were also validated with field data to show increased runtime on sucker rods. The laboratory axial fatigue test showed that the optimized shot peen process increased the fatigue life of the sucker rod approximately 37 times as compared to non-shot peened rod. Sucker rod failures relating to fatigue were tracked after the implementation of optimum shot peen parameters into the manufacturing process and the field data showed a decreasing trend in sucker rod failure rates which supports the laboratory results. This paper presents an insight into how an optimized shot peen process can help to improve the sucker rod quality from a fatigue perspective.