Black Mamba Rod Lift’s helical centralizer stabilizes the rod string during pumping chaos. Chaos is understood as sucker rod buckling and negative loading (compression), which is impossible to eliminate in beam lift wells. The source of compression is often from nature (gas interference, fluid pound, gas pound) but can be operator induced (seating the pump, pump tagging), or compression as part of the pumping method and operation (pump friction, fluid load transition). When compression occurs on standard slick or guided sucker rod, rods experience bending moments, or focused points of high stress leading to micro-fractures which propagate and lead to rod parts. Multiple operators big and small have tested and validated Black Mamba’s system design. By April 2022, we will have had product tested and deployed for nearly 24 months. Operators elect to use Black Mamba for standard guide replacement, but most often opt for Complete, Predictable, End-to-End Rod Control (7 Black Mamba guides per rod), eliminating instability and providing a drastic increase in rod string reliability and rod string life, increasing MTF dramatically. The implementation of rod string stability is most often found at the bottom of the rod string where compression is most prevalent, working upward. Often 3/4" rods have been removed from system and string design due to their low AMOI and increased tendency for buckling. With constant centralization, 3/4" rods take compression and never buckle, following tubing exactly. Sinker Bar replacement is common in deviated horizontals, with the industry transitioning to guided 1” or 7/8” rod body with 3/4" pin connection (reduced coupling diameter allows for extended guide life). This product offering is provided to industry by multiple manufacturers, Black Mamba doing so in Permian, Bakken, Mid-Con. Utilizing 7/8” Slim Hole Couplings (with proper derating) is a good idea for extending rod guide life and extending the time-to-first-contact between coupling and tubing. 1” Slim Hole Couplings are so large they practically render rod guides useless for 1” rod body with 1” pin connection. We discourage the use of standard 1” pin connections when possible. Hybrid sucker rod products are available and actively promoted – 1” HA/HS rod with 7/8” connection reduces coupling diameter, maintains pin-connection strength, and will extend time-to-first-contact between coupling and tubing. Designing rod strings with chaos expected is an ideal method for ensuring the rod string is buckle-proof and ready for any source of chaos, operationally driven or nature driven. Compression Control Rod String Design considers all drivers of instability; the rod string can operate without bending moments, preventing a driving force of pre-mature sucker rod fatigue. Black Mamba’s installations have increased habitual failures by 6x (last 8 failures were at 3 months each), allows operators to pump 192” stroke units at 10 SPM reliably, and removes all guess-work out of string design. Product will have been deployed for nearly 2 years across the world in a variety of pumping conditions.
There is a growing need for energy throughout the world and this increase in demand for energy has now also put a strain on the current sources of energy. In the process of oil/gas production, there are large amounts of water released into the atmosphere as well as into the ground or soil. This water contains chemicals such as Sulphur and Nitrogen oxides, Bitumen, Calcium, Base oil, and Sodium. It is commonly referred to as “wastewater” and is disposed of. The goal of this project is to investigate the possibility of acquiring energy from this wastewater. This is can be done by using various types of soils and water. Various mixtures were created using soils mixed with different percentages of clay and water with varying salinity. A small source of electricity was then applied to the saltwater mud to provide a voltage to the experiment. The chemicals in the mud are then expected to amplify the input voltage and create enough energy to power electrical devices. To prove this, a bulb or small fan will be connected to the mud via an electrode. It was found that clay soil produced more energy than sandy soil. Also, an increase in water volume would dilute the mixture and this would slow down the transfer of energy in the mud. The results of this work can be useful for the environment and the decreasing energy sources.
One of the largest lease operating expenses is electrical cost. Only a small portion of electrical cost is value-added conversion of electricity to fluid lifting power. The rest is lost to downhole friction, fluid flow friction, pumping unit, and electrical to mechanical power conversion inefficiencies. Overall “line to fluid” system efficiency will typically range from 20% to 40%. Some cases will be as low as 10%.
Some of those energy losses are inevitable. Some can be reduced through improved operation and controls. This paper will present power studies of various control schemes on actual wells, highlighting the best solutions for reducing power consumption.
The study will examine: line starters with timers, line starters with pump off controllers, pump off controllers with variable speed drives and advanced embedded controllers. Electrical average voltage(V), power factor, maximum current(A), average current(A), total apparent power(KVA), total reactive power(KVAR) and total real power(KW) will be show for each variation. Apparent costs and ROI of implementing and/or changing to a new control system will be presented.
The use of martensitic alloys in sucker rod applications has several significant advantages over ferritic-pearlitic alloys. Processing differences in making the different microstructures will be discussed, along with the resulting property and performance differences. An evaluation of the guidelines for optimal strength in various corrosive environments will be provided. Studies on the fatigue performance of martensitic and ferritic steels will be presented.
In 2016, a recommendation was made in EOR to begin utilizing Grade “C” when replacing rods in San Andres wells or wells less than 5,000’ deep. The advantage of the Grade “C” rods believed to be better corrosion resistance, tubing leak reduction, and lower material cost. It was also recommended that “T” coupling be considered as an alternative to Spray Metal (“SM”) couplings as they are softer and should fail preferentially to the tubing. As with any technology that is new to the field in question there is concern about wide spread use until sufficient data is gathered on a smaller subset of wells to prove up the concept. As failure frequency is a key metric when evaluating artificial lift performance, and it can take several years to develop sufficient data, an analysis method needed to be utilized to track the equipment performance over a shorter duration so that use can be expanded as early as possible. This was accomplished by developing statistical data for sucker rod and coupling installations and failures over a specific time period comparing the failure rate of the “C” rods and “T” couplings versus the “KD” rods and “SM” couplings that are typically run. The analysis showed that the “C” grade rods and “SM” couplings were not showing an increased failure rate and therefore provided support to start expanding their use in EOR, which should result in significant cost savings. To further understand the corrosion differences between C-Rods and KD-Rods corrosion coupons were constructed from sections of actual rods and placed in several wells of varying characteristics. This paper will also present the findings from this corrosion test, which is currently nearing completion.
Different types of forces NOT accounted for by the wave equation are 1) mechanical friction, 2) piston force acting on the polished rod due to tubing back pressure and 3) true vertical rod weight. Mechanical friction will be discussed from 1) over-tight stuffing box, 2) down hole sticking due to a severe dogleg in the wellbore profile and 3) friction from paraffin along a section of the rod string. The application of these external mechanical forces acting on the rod string impacts measured surface loads, down hole stroke length and plunger velocity, plus the calculated rod loading at the pump or other locations in the rod string.
Damping coefficients are used to subtract out fluid damping as a function of velocity along the rod string using the wave equation. Unaccounted for mechanical friction cannot be modeled by adjusting the damping factors in the wave equation. Mechanical friction impacts both the shape of the pump card and the measured surface dynamometer card loads versus position and, as friction on the rods goes up then the surface load range also changes. Field measured dynamometer data will be used to show examples of these different types of forces NOT accounted for by the wave equation
The objective of this paper is to share insights on mitigating sucker rod corrosion damage in vertical, horizontal and deviated wells with aggressive corrosive conditions such as H2S and CO2, particularly those with histories of corrosion-related rod/tubing failures.
Corrosion is a common problem in production operations, accounting for two-thirds of all rod string failures and costing billions annually to remediate, according to NACE International. This paper presents the development and initial field application results of a continuously applied metallic coating that actively participates in the electrochemical aspects of corrosion in carbon and low-alloy steels. Moreover, the solution protects uncoated segments of rod and other steel components in the wellbore while reducing abrasion by enhancing friction properties compared to bare steel.
The authors outline the key properties and characteristics of this coating, including evaluating its performance relative traditional corrosion protection measures such as barrier coatings. Rather than acting as a barrier layer, the metallic coating actively protects against corrosion and has inherent chemical properties that self-heal surface scratches and abrasions. This is particularly valuable in horizontal and directional wells with high dog leg severities and sideloading forces that contribute to rod/tubing abrasion.
Results are presented from laboratory testing as well as initial trial applications in wells with histories of rod failures due to corrosion, typically requiring interventions with workover rigs. In one such trial, the metallic coating was applied to a coiled rod string installed in a high-CO2 content well on progressing cavity pump. The coated coiled rod string was installed in January 2019. Ater five months of service, the coated string was pulled to inspect its condition. The examination revealed that the rod was unaffected by corrosion. A second inspection after nine months found evidence of rod string wear but no corrosion damage. The well has been in continuous operation for 35 months (and counting), more than doubling the average run time before installing coated coiled rod.
The novelty of this approach is the application of an advanced materials science coating to extend rod string service life in corrosive environments through active protection. In addition, it requires no special handling or installation equipment, and the metallic material allows rod strings to be recycled (eliminating potential environmental and downstream damage risks associated with barrier coatings).
As supported by lab and field case study data, the results of deploying this method include increased production uptime, reduced workover frequencies and associated remediation costs, and lower overall LOE and lifting cost per barrel of oil produced.
To increase recovery rates – the greatest challenge facing the industry – operators must not only look to step-change technologies, but improvements to existing technology. Even incremental increases in recovery rates can impact economics when multiplied across numerous wells. For example, approximately two-thirds of onshore wells use beam operated pump jacks with reciprocating rod pumps. Our objective was to improve the efficiency and reliability of sucker pumps by engineering a new ball valve insert. Prototype testing demonstrated that the lowest pressure drop was provided by an insert design with the tangent angle equal to Pi (3.14, π), as it forced the fluid into a vortex spin. Based on a number of flow rates (including two phase flow) the TangentFlow Insert decreased pressure drop by 40% on average resulting in 58% more flow than the bar-bottom inserts. In addition, compared to the bar-bottom inserts, which produced significant ball chatter, the TangentFlow Insert had a consistently low decibel reading with increasing flow rates, as the ball remained stationary. This results in reduced gas breakout, which in turn further reduces pressure drop, fluid pound and pump damage. One-year field results from 50 wells in the Red River reservoir of Montana and North Dakota demonstrate that the TangentFlow Insert reduced pressure drop across both the standing and traveling valves to increase average surface flow by 8%. Considering the average water to oil ratio in the area, this provides an additional 3.1 bbl/day/well. This increase applied over 50 wells translates to approximately 54,603 bbl/year, or $3.33MM in revenue at current oil prices. The design of the TangentFlow Insert improves the efficiency and reliability of sucker rod pumps by minimizing the effects of pressure drop, gas breakout, solids accumulation (wax), casing wear and ball wear, which together improve pump efficiency and production flow. Because the design enables the ball to remain stationary, smaller and lighter balls can be used, allowing for higher flowback solids and reduced cage wear, respectively. The TangentFlow Insert is manufactured to replace conventional bar-bottom inserts without needing to change out the entire pump assembly, making them applicable to 90% of pumps presently used in the industry.
Decline Curves Analysis commonly ordinarily applied to evaluate the original hydrocarbon in place, hydrocarbon reserves, and forecasting future production performance. The Decline Curves Analysis development was presented by Johnson and Bollens in (1928) and later on (1945) which is called "loss-ratio". Many discussions of the mathematical relationship between the past time, production rate, and the cumulative production depend on the decline rate. Decline Curve Analysis is a technique which might be stratified for a single well or whole reservoir by either production engineer or reservoir engineer. In oil industry, remaining reserves are the substantial target. The objective of this study is to determine and clear estimation of a reservoir performance in Libyan Oilfields by using Decline Curves Analysis and estimate the reservoir life. Also, in this work we simulate the production operation data to find out the better matching of forecasting results and the economic impact of the selected reservoir. This research is an attempt to determine one of Libyan reservoir performance and determine which one of the three classifications of the Decline Curves are Exponential, Hyperbolic, and/or Harmonic by using one of the most widespread important reliable methods to estimate the depletion of reservoir pressure with the consideration of the method limitations, the changes in the facilities downstream, and hydrocarbons production rate.
Horizontal wells are the largest capital investments made in the Permian and return on investment is essential. This project was developed to analyze the sustainability of gas lift as final form of artificial lift for unconventional horizontal wells. A pilot to run gas lift equipment deep into the lateral was developed, which involved meticulous candidate and downhole equipment selection. Two horizontal wells were selected, and deep gas lift was installed far into the lateral.
How and where ground wires are connected determines the runtime and successful withstanding of switching and lightning surges. This is extremely evident with lightning protection of electric submersible pumps (ESP). Electric surge suppressors on the same ground wire can and will interact bidirectionally in a lightning storm. Instances of ESP failures due to improperly installed surge suppression are not uncommon. Understandably the value of surge suppression has been questioned. This paper proposes separate ground wires for each surge device with all wires bonded together at the wellhead. Justification for this is derived from multiple engineering reports on wellsite electrical installations, electrical theory and reported extended ESP run-life.
The purpose of this paper is to discuss the history of different gas lift design methods and the theory behind a new design method. In January 2019, Production Lift Companies and Concho Resources ran a new gas lift design method in two unconventional wells in the Permian Basin. This new method is designed to exploit the initial high bottom hole pressure in unconventional wells to produce higher rates that, before now, were only possible with an ESP. This life of well design will also follow the well’s decline and efficiently produce the well at lower rates. When completed correctly, the well can be switched to PAGL, Plunger Lift or GAPL without pulling the tubing.
The traditional gas lift design method for unconventional wells is to run unloading valves until you reach a minimum spacing of 500’ (Fig. 1) and then continue the 500’ spacing to the packer. The 500’ spacing was adopted by the industry in the late 80’s as “Best Practice” and has remained the standard today.
Since its’ introduction to the unconventional oil and gas realm in 2018, Single Point High Pressure Gas Lift (referred to as HPGL going forward) has emerged as one of the top artificial lift choices for operators in the Permian and Anadarko basins. It has become a proven technology with over 1,250 applications to date as more operators are choosing it as their primary form of artificial lift for their unconventional assets. Its ability to achieve sustained high fluid rates as well as having a high sand and gas tolerance makes it the most versatile form of artificial lift offered in today’s market. HPGL is not a new concept having been discussed in SPE 14347. (Dickens, 1988) The concept was revitalized in SPE 187443 (Elmer, Elmer, & Harms, 2017) by which the authors of this paper emphasized its’ application for horizontal wells though at the time the needed compressor technology was not widely available to the market. This has changed as compression service companies have begun offering compressors designed to achieve the high discharge pressures needed to initially unload wells. This has led to a surge in HPGL applications as operators are looking to maintain the high output capabilities of ESPs with the benefits of gas lift. Gas lift is a naturally flowing process; therefore, it is important to understand the pressure drop across the entire system to achieve the desirable outcome. There are many components along the flow path from reservoir to sales that affect this pressure drop. HPGL has re-emphasized the importance of Nodal Analysis, and the understanding thereof, to production engineers. Proper design and installation of each node can drastically sway your well’s performance capabilities therefore proper modeling must be conducted to ensure the desired outcome is achieved. In this paper we will demonstrate the HPGL design method used today to ensure optimal output will be achieved.
Managing extensive Electrical Submersible Pump (ESP) operations and evaluating their performance can be a challenging task, especially in unconventional reservoirs. Varied operational environments, expansive geographical areas, large ESP populations, different declination patterns, diverse fluid properties and well designs and different service providers are some of the complications that operators face every day. Many companies measure the success of any artificial lift project focus on simple run life statistics as the central key performance indicator; however, these types of statistics may not always be enough in providing significant information to decision makers. It is vital to the success of any project to establish a performance evaluation structure that can effectively capture deficiencies and highlight potential improvements. Survivability curves are the result of the statistical model based on Kaplan-Meier analysis, which was originally created to measure the fraction of subjects living for a certain amount of time after treatment in clinical trials, so similar methodology was deployed to analyze an important dataset of ESPs to deeper understand by factoring and comparing elements which influence ESP run life, showing results that are easier to understand and represent real value to operators on several areas as safety, engineering, reliability and operations. As a result, from this comprehensive study jointly initiated between an oil operator and ESP vendor, corrective actions were taken that drive improvements in all ESP aspects, which can be seen not only in today’s KPIs, also influence future artificial lift projects. Being able to draw conclusions about the expect runtime can be used to drawn insight on find areas where efforts should be focused to improve ESP reliability, find where ESPs can be best utilized to improve field performance, and identify opportunities to reduce workover cost. Similar analysis can be done to visualize ESP runlife improvement over time, compare different ESP technologies, and find expected runtimes by completion design or producing formation. The values of insights gained from statistical analysis can be gotten from any field of ESPs to aid in making better oilfield business decisions.
The perceived impact of chlorine dioxide (ClO2) on the corrosion of steel used in the oil patch has been a controversial issue for many years. Although a few studies on this issue have been published, those results have been contradictory. As concerns surrounding this issue continue to be raised, a systematic study has been undertaken to understand the corrosive effects of ClO2 towards steel in various produced waters. Research shows that the baseline corrosion rate of untreated produced water is related to TDS, with other factors being involved, such as the presence of H2S and iron. This paper summarizes the results of other studies that have been done, and demonstrates the contradictory nature of such studies. The results of this on-going study show the relationship between the TDS of produced water and corrosion resulting from use of varying concentrations of ClO2. The paper explains the contradictory nature of corrosion caused by ClO2.
Wells with high depletion rate present high free gas at pump intake conditions. In all cases, the production of fluid with a high gas-liquid ratio leads to an inefficient performance of the rod pump systems. The initial solution to this problem is the installation of poor boy gas separators which capacity of gas separation is reduced and do not provide a high-performance solution. Packer type gas separators are the most efficient downhole separators in the market, however, they usually have some operational limitations. This paper summarizes a new design of the packer type gas separator which uses more methods of separation than the traditional design and can be designed based on the conditions of each well overcoming the typical limitations. The design criteria are reviewed, and some operational guidelines are listed to reach the best performance in each application for gas separation.
When optimizing a reciprocating rod lift installation, key control parameters must be extracted from the downhole data. Traditionally, downhole data in the form of position and load data is derived from surface data using the wave equation. Downhole position and load data must be carefully analyzed to extract key control parameters for reciprocating rod lift optimization.
IRIS introduces a new and innovative approach for downhole data analysis.
Through a change in coordinate system, IRIS transforms downhole position and load data into polar coordinates. This change in coordinates creates three new data sets, which greatly simplify the extraction of the above mentioned key control parameters.
Additionally, IRIS can be used to manage both viscous and mechanical friction through an extra friction detection algorithm and a viscous damping estimator.
In this paper, the IRIS algorithms and results are presented.
As fluctuations in oil price continue, the industry has changed and is demanding improvements from each method of artificial lift. Required flow rates are increasing due to the longer laterals of new horizontal wells being added to inventory. Rod Lift is not immune and is being asked to enter the artificial lift cycle earlier and support the pumping of wellbores with added complexities due to geometries and/or production demands. The fiber reinforced plastic (fiberglass, FSR) rod continues to meet the ever-increasing demand and complexities. The two previous editions of ‘IT’S ALL ABOUT THE END FITTING’ focused on the design of the new generation of fiberglass rod, the added strength the industry has requested, the benefits regarding the handling of compression and methods to mitigate uncertainties of the wellbore dynamics. This edition will focus on benefits of the latest generation of the end fitting. It will explain how a new configuration of the wedge profile provides reduced pressure drop at each connection and/or adds corrosion resilience. The new wedge profile also increases the ability of the end fitting to handle compression. Data will be provided in support of increased production. The fiberglass rods have been delivering benefits for the last 30+ years to the industry and continue to maintain pace with growing demands of artificial lift through innovation and development of new generation FSRs. With an ongoing progress of FSR technology the glass rods are being adopted earlier in the well’s life cycle requiring us to make the product RUN LONGER & PRODUCE
The objective of this paper is to share insights from a case history of jet lift applications in the Permian Yeso play. Apache Corporation was among the first operators to deploy horizontal drilling and multistage fracturing in the Yeso formation in Eddy County, N.M., targeting dolostone/limestone/sandstone reservoirs interbedded with shale and anhydrite. The Yeso yields oil and liquids-rich gas at depths averaging 5,000-6,000 feet. Apache’s initial strategy was to commence post-flowback production from fractured wells with electrical submersible pumps, and then transition to rod lift as rates declined over time. However, as the wells approached the transition window between ESPs and rod pumps, high sand content and gas-to-liquids ratios caused frequent downtime for both types of lift, negatively impacting well performance. To counter these problems and accommodate the solids and GORs, the operator installed concentric string jet lift. This solution effectively bridged the application gap between high-rate ESPs in early well life and lower-rate rod pumps later in the lifecycle. Referencing the well data, the results section summarizes how jet lift operations successfully handled variable flow rates with high GORs / solids while achieving targeted drawdown and production output. The results demonstrate that jet lift improved uptime, maintained expected production decline, and reduced cost by eliminating frequent workovers to repair rod pump components. The novelty of this approach is the extended application range for jet lift, emphasizing its inherent flexibility in transitioning to different forms of artificial lift to meet changing production profiles as horizontal wells progress through their characteristic steep decline curves when faced with a deviated well that will increase rod-on-tubing failures and premature wear of the pump. The discussion synopsizes jet lift’s applicability across the lifecycle in horizontal resource plays, and the problem-solving benefits of concentric tubing string designs. The paper concludes with an assessment of jet lift’s evolving capabilities; specifically, how advancements in downhole sensors, remote monitoring / automation, and digital optimization are capturing value and enabling operators to deploy jet lift as an alternate lift system.
Oxy Resources established the Texas Delaware Team in April 2013 when ~200 wells were purchased in the area of Pecos, Texas. These primarily vertical wells produce from various commingled Delaware intervals located at 8,000’ to 12,000’ deep. The nature and deviation of these wells have made rod pumping them challenging and failure frequencies have been as high as 1.5 failures/year. Many lessons have been learned in driving the failure frequencies down to the current level of 1.0 failures/year. This paper will share some of the lessoned learned using various equipment types including fiberglass COROD, Poly-keytone Lined Tubing, Poly-keytone Rod Glides, and Variable Slippage Pumps.
There are three components to a successful rod lift surveillance and analysis program. One, a rod pump off controller is needed to match inflow to outflow, reduce fluid pound when configured properly, and to shut the well down in the event of a downhole failure. Secondly, a host system is needed to provide immediate identification of downed wells, remote surveillance, and the ability to monitor and analyze hundreds of wells per day, enabling quicker identification of variances and solutions. And lastly, and of equal importance is to establish and implement business rules, work processes, and best practices that leverage the pump off controllers and host systems. In today’s world of ‘do more with less’, all three steps are needed to realize the full benefit of automation, and to achieve full optimization. Operators tend to spend the upfront dollars, which is by far the majority, for the hardware and software, but oftentimes never realize the full benefit due to not dedicating the resources, training the employees on technical Well Analysis, and implementing the supporting business rules, work processes, and best practices. The presentation will describe a situation in which a company utilized pump off controllers and a host system, but were lacking the business rules, work processes, and best practices to complement the hardware and software. The company leadership recognized gaps in skillsets, missed opportunities, and basic lack of understanding of the value of automation, and engaged ChampionX to do an assessment, or ‘health check’ of their fields and wells. A clear before and after picture of the metrics will be shown in the final paper. Below were the initial steps. 1. Both parties met to determine which metrics were to be measured, and acceptable targets/ranges. Below is a sampling of the individual metrics to be measured. a. Number of wells in some state of alarm. b. Wells cycling excessively. c. Wells with low volumetric efficiency due to over pumping or loss of displacement. d. Wells in need of additional lift capacity. e. Wells running with excessive SPM. 2. ChampionX Consultant mined, assembled, and presented the data to core team within said company. Each metric received a score. 3. Company Leadership presented findings and results to broader audience within Company operations. 4. The metrics and targets were adjusted where needed. 5. Workflows were built for each metric outlining the specific steps to take describing ‘how’ to improve the score. 6. Business rules were established for each metric describing ‘who’ and ‘when’ various steps are to be taken. 7. Each metric was assigned an ‘owner’. 8. The status of each metric is publicized daily via internal dashboard. With this exercise, it was immediately apparent to the company’s leadership team, and other personnel that the ROI on their automation system was significantly lacking. The presentation will show the value gained from implementing the third piece of the process.
A dual purpose design is presented in this paper to face high gas presence and sand production conditions in petroleum wells with an Electric Submersible Pump (ESP) system installed. The results of this design’s application in severely problematic wells, due to high gas and sand production, will confirm the importance of conditioning the fluid before it gets to the pump intake.
This engineered design consists of different stages from the isolation of the pump intake until the tubing bodies in charge of gas and sand handling. Engineering concepts were applied in the construction of this solution such as gas re-solubilization, changes of pressure and velocity, agitation, and vortex effect to finally present a design that is capable of breaking gas slugs into smaller gas bubbles that can be produced by the ESP system without impacting its performance, and at the same time separating fine solid particles (<250 microns) using centrifugal forces.
Case studies from wells located in the Permian basin will better explain the positive impact of selecting a proper downhole conditioning system to improve the ESP systems efficiency. A drastic improvement on the sensor parameters will also illustrate the effect of handling the gas and sand before the pump intake, which also leads to one of the most important consequences: A decrease in the number of shutdowns, which in turn decreases non-productive time, resulting in positive impact of fluid production. Additionally, the flexibility of this design is significant, since it allows it to be installed in a wide range of fluid production, gas-liquid ratio, tubing and casing sizes.
The novelty of this new design is the addition of the surge valve below the packer, which accomplishes multiple purposes: to avoid surging in the well, to allow testing the packer to assure it is properly set, and finally, allow chemical injection below the packer.
Rod pumps are not the ideal system of lift when it comes to handling gas. We can only do so much with the configuration downhole especially for wells with open hole completions. Despite the limited options, we are coming to find that we can do better by manipulating parameters at the surface. Historically, we have manipulated back pressure on the tubing in order to control when gas breaks out of solution in the tubing. Now we are finding, on certain well types, that manipulating back pressure on the casing in order to keep gas in solution through the pump is proving to be successful. By doing this, we are seeing beam wells that now face less equipment stress due to gas interference, more consistent, stable run time and production on a daily basis, and even optimized inflow where production increases for wells.
There are many challenges associated with sucker rod lift in deviated wellbores that can lead to high failure rates and lost production. Tubing failures are amongst the costliest workovers and are often a result of metal to metal contact between the rod coupling and the tubing. Evaluating tubing on-site using both gamma and electromagnetic inspection allows for proper design optimization before returning to production. The tubing scan can be aligned with deviation data, previous rod design, and failure history to adjust the string design to effectively extend mean time between failures and improve asset value. An effective rod guide strategy was developed to mitigate tubing wear using proper guide type, material, and placement. The implementation of this strategy has helped to maximize production efficiency across the asset.
The common surface chemical applications cannot reach or have low efficiency due to high fluid levels. This paper Introduces a new chemical technology for all types of artificial lift systems that guarantees an efficient downhole treatment at the entry point and summarizes the applications of this revolutionary method established to deliver chemical combinations by microencapsulating the compounds and packaging the completed formulation in a chemical screen that is placed at the bottom of the tubing (BHA) below any type of artificial lift systems. The new downhole Chemical treatment technology were designed and successfully applied in 3 wells in the Permian Basin to control scale and corrosion. The installation of the chemical tool is easily made up below the pump intake and not additional equipment is needed in the pump or in the surface facilities.