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

Oasis Petroleum has ~1000 rod pump wells in the Bakken producing from 8000’ - 10,000’. A focused effort has been made over the past few years to reduce the failure rate from ~1.0 failures/well/year to the current rate of .68 failures/well/year. This has been the result of a holistic approach which has encompassed improvements in rod design, surveillance, training, development of Standard Operating Procedures and Best Practices, trialing new technology and POC optimization. This paper will document some of the successes and failures during this journey.

The Artificial Lift Intake Isolation (ALII) tool is a new technology for rod pumping wells that when activated isolates the production tubing. The tool provides positive well control prior to breaking wellhead containment providing significant cost savings, safety and environmental protection. The tool is a simple two-part system, the first being the valve portion which is run just below the client’s pump-seating nipple in the production tubing string. The second is the actuator, which runs on the bottom of the insert rod pump. Tool activation is accomplished by simply running a rod pump with the actuator attached. When the pump is seated, the valve is opened for production; and when unseated the valve closes, isolating the tubing. The tool can be cycled multiple times. No additional equipment is required for tool operation and 100% positive shut off is provided which eliminates the need for kill fluids and eliminates the chance of formation gases or other fluids being released at the surface. There is no need for control lines to open and close the tool and there is the capability for utilizing the pump jack to cycle the tool open and closed. The tool also provides the capability for pressure testing the tubing when in the closed position. A number of benefits accrue through application of the tool to pumping wells and includes cost savings from reduced rig time to surface and re-run rod pumps, reduced trucking costs, reduced storage costs for kill fluids and minimizes the number of non-pumping days. Increased safety is realized as the tool provides positive well control prior to a well workover eliminating the chance of formation gases or other fluids being released at the surface. Environmental advantages include reducing the environmental footprint by decreasing water usage saving the local water supply. 

With the increase in activity in the Delaware Basin, preparing wells for the pressure spikes seen from offset fracs is crucial in order to maintain safe operations.  It is important to take risk and economics into account when deciding how to prep a well. Most importantly, historical data should be factored into the decision making process and used to build the program guidelines.  Factors that should be accounted for are artificial lift type, surface equipment ratings, producing interval, frac azimuth, and 
relative distance and position to the well being fractured.
 

Rod lift design methods remain overwhelmingly unchanged since the mid-20th century. Meanwhile, drilling and completion technology has undergone a dramatic transformation. The innovation gap between the two technologies and low-flow artificial lift has resulted in the need for improved design and workflow methods to more effectively operate an unconventional well throughout its lifecycle. New design and workflow processes have been developed that improve upon today’s common practices through the observation of unconventional well characteristics and root cause analysis of equipment failure. This new design and workflow process has resulted in improved performance for unconventional wells in the Permian Basin.

Case study of mill-out operations in the Permian Basin which evaluate chemical program and processes used. Results show how existing processes and chemicals used or lack thereof, can affect equipment and undo the preventative chemical treatments used during the hydraulic fracturing process. The study looks at field water testing performed during various mill-out operations and considered workover rig vs coiled tubing, equipment set up, water & chemicals used, and operational challenges. Water analyses were completed on injection water and returns at various interval of the mill-out. Effectiveness of chemical treatment was also monitored when biocide was used. Four field case studies are presented for horizontal wells. Two wells were milled-out utilizing workover rigs and two wells were completed using coiled tubing. Testing results show the impact of equipment setup and operations process on the water quality and efficiency of the chemicals used. Water fouling was prevalent in all cases, with coiled tubing jobs showing the highest degree of water contamination and chemical inefficiency. Changes in water treatment program during operations showed significant improvement and sustainable results. Potential corrosion of the work string due to water fouling and composition was also observed, and the effects of changes in chemicals were monitored. This is important because it identified operational improvements that can reduce equipment replacement costs, chemical overuse and protect wells from fouling due to high bacteria. This case study provides a comprehensive review of mill-out operations and provides guidelines for improving chemical efficiency and potential of  extending life of the work string.
 

Data from fluid level shots can be very valuable in optimizing the chemical treatment program. For example, selecting continuous treatment vs truck treatment, adjusting flush volumes on truck treated wells, ensuring slip-streams are open and adequately slipping, or raising the SN depth on wells that cannot be pumped down. Just because chemical is being introduced into the backside does not mean it is effectively getting downhole, or getting downhole at all. This is especially true with flumping wells that are particularly hard to treat without a cap-string (although operators often apply cookie-cutter treatments for the whole field without taking individual well differences into account). Different methods of introducing chemical into the well and ways to overcome chemical treating challenges will be discussed and tied into how data from fluid level shots can help guide better decision making.

Production performance monitoring has existed in Rod Lift Artificial Lift for decades, however there has lacked any action based on performance parameters. The Total Production Real Time (TPRT) Monitoring System incorporates data acquisition with artificial intelligence and automation to provide safer production operations for personnel and environment. TPRT collects live production data at surface on Rod BOPs, Stuffing Boxes, and Rod Rotators then drives actuation based on performance outside of expected performance parameters. For example, when a leak is detected at the primary seal for a Stuffing Box, TPRT engages a secondary actuator to recompress the seal, maintaining environmental control of the well during production as opposed to current product solutions which simply shut off the pumping unit at this minor inflection point on equipment performance. TPRT utilized point-to-point data acquisition and transmission to provide operators with live, cloud-based performance data on remote wells. The core functionality of TPRT is to maximize productivity while protecting from environmental leaks and limiting unnecessary visits to well sites.  
 

With the development of new digital technology over the last several years, our industry has seen many benefits of remote monitoring and automation in sectors within drilling, completion, and production. One area that has lagged is remote monitoring and automation of production chemicals applications. This paper will review initial pilot testing of automated chemical pumps on a group of newly completed wells. The initial objectives of this pilot test were to 1) seek to identify potential chemical cost savings during the early life of the well by autonomously linking chemical injection rates to production volumes; 2) confirm that chemicals are being consistently applied at the prescribed dosages; 3) set up notifications alerting personnel of potential problems, such as low tank volume or inadequate power supply; 4) be able to use the historical chemical tank level data to assist in approval of chemical delivery invoices; 5) determine if operational efficiency of chemical vendor can be improved by needing to check tank volumes and pump rates less frequently; 6) help identify other applications in which this technology could be beneficial such as saltwater disposal chemicals or methanol injection for compressors. Methods, Procedures, Process: Automated chemical pump controllers with built-in communication devices are used to monitor and optimize chemical injection rates. The chemical pump controllers are then able to be remotely monitored and controlled using optimization software. A prescribed dosage target of chemical to production volume is assigned in the software where the software then calculates dosing rate each time a new well test is entered. The software sends the new dosing rate to the chemical controller. We also configured the software to send automated emails to the Well Optimization Analysts and the chemical vendor representatives to alert personnel of low tank volumes or low voltage issues. Results, Observations, Conclusions: The supply voltage would drop so low during the night that the pump would stop pumping. We had to upgrade our solar power system on certain wells to provide enough power to consistently achieve target chemical injection volumes. We then set up low voltage alarms so that we are immediately notified if there is a problem with the system. Also, by remotely monitoring tank levels and alarming on low tank levels we ensure that chemical deliveries are made on time. Another benefit from monitoring and trending tank levels is the ability to use the historical data to assist in confirming chemical invoices. Novel/Additive Information: Chemical programs have historically been controlled manually by a chemical vendor technician or operator on location in a reactive manner. Chemical tanks running dry, the loss of power, and lack of accountability can all be mitigated and resolved by automating chemical injection and enabling remote control. 
 

For decades sucker rod pump artificially lifted wells have used devices called pump off controllers (POC) to match the pumping unit’s runtime to the available reservoir production by idling the well for a set time where variable frequencies drives are not available. In doing this the POC allows the well to enter a set period of downtime when the downhole pump fillage is incomplete to avoid premature failures, and then brings the well back online to operate before production is lost. Although this method has been successful for several years, autonomous control algorithms can be utilized to reduce failures or increase production in cases where the downtime is not already optimized. Optimizing the idle time for a sucker rod pump artificially lifted well involves understanding the amount of time required to fill the near wellbore storage area before generating a fluid column above the pump intake that will begin to hinder inflow from the reservoir into the wellbore. By varying the idle time and observing the impact on production and cycles the program hunts for the optimal idle time. By constantly hunting for the optimal idle time the optimization process can adjust the idle time when operating conditions change. This gives the advantage of always meeting the current well bore and reservoir conditions without having to have a user make these changes and determine what the downtime for the well is. Autonomously modulating the idle time for a well, if done properly will either reduces incomplete fillage pump strokes, in cases where the idle time is too short, or will increase the wells production in cases where the idle time is too long. Overall this will result in the optimization of wells by reducing failures and/or increasing production, generating a huge value to the end user by automating the entire process of downtime optimization.
 

Variable Frequency Drives (VFD) are a well-known method of pumping beam wells. By running the well continuously and adjusting pumping speed based on pump fillage, they provide unique benefits to reduce failures in difficult environments as compared to operating in pump-off control (POC); these environments might include solids, buckling tendencies at pump-off, and CO2 WAG environments. Although the industry recognizes the VFD benefits, many candidates remain on POC due to the capital investment required for a VFD purchase. This paper discusses two assets within Oxy Permian EOR and analyzes the economics of VFDs in order to assess if expanded usage is justified.

The Apache-operated Adair San Andres Unit (ASAU) currently employs fifteen capillary string (cap string) equipped producing wells, representing 16% of the active producer count. Apache started converting producing wells to cap strings in 2016.  This idea was introduced to Apache at the 2012 CO2 Conference in Midland and later reinforced during a field tour of Whiting’s North Ward Estes CO2 flood in 2015.  The chief benefit using a cap string is production stability.  A review of these installations 
is categorized by a reduction in production variance, meaning an increase in stability - be it oil and gas production, or water-oil and gas-liquid ratio (GLR).  This equates to less rig intervention, more uptime.  Of note: 1) a cap string will successfully operate below the minimum GLR of 400 SCF/BBL/1000’ required by plunger lift, 2) conversion to cap string assisted lift is not affected by the wellbore geometry, and 3) ASAU installations are packer-less.

Electric Submersible Pumps (ESPs) are severely affected by free gas entering the pump, which cause significant degradation in pump performance, due to gas locking conditions cause by bubbles blocking the fluid from passing through the impellers, resulting in frequent shutdowns and restarts, which increase the risk of early failure. This effect is even worst when a gas slug event, very common in horizontal wells drilled in unconventional reservoirs, hit the system, this event consist of a large volume of light density fluid (gas) flowing through the system, overheating the motor and pumps due to a no liquid flow condition, resulting in unstable production due to ESP shutdowns caused by underload or high motor temperature. The industry has used shrouds, rotary and vortex gas separators, and more recently, multiphase pumps to handle the gas, however, there are some applications where this equipment is not enough to handle the Gas Liquid Ratio (GLR). Recently two Oil Operator Companies in the Permian basin following our recommendation successfully installed a multiphase encapsulated production solution technology to separate the gas from the liquid in the wellbore. As produced fluids, pass the pump at high velocity, the heavier liquid falls back into the shroud in a low-velocity area between the tubing and the top of the shroud, allowing the gas to continue to the surface. This system has proven to separate the gas from the liquid effectively (> 90% of efficiency), stabilizing operations within a certain operating window. In this document, results are shown for two successful field cases, how uptime improved, being able to reduce the number of shutdowns, improving operational performance and increase the drawdown maintaining stable production of the wells. 
 

Data from fluid level, dynamometer, pressure, and motor power measurements were acquired by a standalone programmable monitoring system that uses internet and cellphone communication with the Cloud for remote monitoring of well performance. The system named Remote Asset Monitoring or RAM is described in detail in this paper that presents results from the tests that lasted several weeks, beginning with well pump down, just after new pump installation and continuing during normal production operation. The performance of the well was monitored in detail and additional measurements were acquired as needed based on the real time performance of the pumping system. 

In the past an operator was required to be at the wellsite to perform these tests. Once the portable RAM system was deployed at the well site and was programmed for standalone acquisition, the well performance trends were monitored wirelessly over extended periods of time without requiring an operator to return to the wellsite.

When connected via the cloud, the data acquisition schedule was adjusted remotely and the stored data was viewed and retrieved as needed. Additional measurements were performed and interpreted in real time so that the operator was able to troubleshoot and analyze the performance of the well from any location in the world.

Failures due to Rod wear and tubing wear account together for an approximate range between 50% to 70% of the OPEX in Rod Lifted systems. Industry has made significant improvements by separating the steel components during their relative movement by using different materials in between them and as sacrifice components. The rod guide is one of them and it comes today in several shapes and compositions. One of those compositions, and the most successful one, is the plastic guide. In the pursuit of the best plastic for West Texas wells, Oxy and Tenaris teamed up to assess Polyketone plastics with varied concentrations of glass fiber and seeking options to reduce the friction factors of this polymer on tubing ID. This paper describes the features in the selected polymer, the different configurations considered, an overall view to the qualification program, key quality assurance steps to comply with Tenaris QMS. Finally, Oxy’s implementation of the guides and the results from the operations. Since March 2020 Tenaris started supplying guides with this polymer to Oxy. To the date of this publication more than 50,000 guides have been installed with zero failures reported. 

Water block after hydraulic fracturing is one of the major challenges in shale oil recovery which affects the optimal production from the reservoir. The water blockage represents a higher water saturation near the matrix-fracture interface, which decreases the hydrocarbon relative permeability. The removal of water blockage in the field is typically carried out by soaking the well (i.e., shut-in) after hydraulic fracturing. This soaking period allows water redistribution, which decreases the water saturation near the matrix-fracture interface. However, previous field reports show that there is not a strong consensus on whether shut-in is beneficial in term of production rate or ultimate recovery. Due to the large number of parameters involved in hydraulic fracturing and tight formations, it is challenging to select which parameter plays the dominant role in determining the shut-in performance. Furthermore, literature on field case studies does not frequently report the parameters which are of researchers’ interest. In other words, the challenge of evaluating shut-in performance not only lies on the complexity of parameters and effects involved within the reservoir, but also the limited number of field case studies which report a comprehensive list of fracturing and reservoir parameters.

This paper aims to investigate the effect of well soaking timing on shut-in performance. This question is motivated by the fact that in the field, shut-in can take place either immediately after hydraulic fracturing but before the first flowback (i.e., pre-flowback) or sometime after the first flowback (i.e., post-flowback). The timing of shut-in is believed to influence the production performance, because it dictates how much water will imbibe from the fractures. A numerical core-scale model is built and validated by a successful history match with numerous experimental data. Our model demonstrates that shut-in performed after the first flowback (i.e., post-flowback) can help ensure a higher regained oil relative permeability than shut-in performed before the first flowback (i.e., pre-flowback). A discussion on the water blockage mitigation from these two shut-in timings is also presented. As a result, this study proposes that flowback should be carried out immediately following hydraulic fracturing, even if an extended shut-in is to be performed later.

Surface coatings are commonly used in many industries including oil and gas; with the aim of hardening the part surfaces to improve wear resistance without compromising the corrosion resistance -or even improve when applicable. Sucker rod pumps employ several parts with coated surfaces as well, including the pump barrels. Both standardized surface modifications and specialty applications for pump barrels are readily available in market for different well conditions, including extreme well solids and H2S and CO2 service. These service conditions can be detrimental for pump performance if the right coating is not used. In addition to service conditions, well treatment methods such as acidizing can also deteriorate the coating performance, causing pump failures. This study focuses on the structure of 6 different standardized and specialty coatings on sucker rod pump barrels and an experimental study on their degradation in acidic environments, while familiarizing the reader with the recommended service conditions. 
 

Rod pumping unconventional wells is becoming increasingly challenging due to unpredictable downhole environments. Many unconventional wells exhibit significant deviation accompanied with corrosion making them difficult to rod lift without exposing downhole equipment to unpredictable damage mechanisms – specifically the rod string.

Continuous rod is a proven technology in these deviated unconventional wells as it increases the mean time between failures through lack of connections and distributed side loads. Although continuous rod will increase the mean time between failures, all rod pumping systems will eventually require an intervention. Traditionally, when continuous rod is pulled during a workover, inspections have been done visually in the field by experienced rig crews. However, this method is imprecise and subject to human error. This can result in unexpectedly early failure after a satisfactory inspection or additional cost from replacing mechanically serviceable continuous rod strings.

The Low Voltage – Electromagnetic Inspection (LV-EMI™) unit will detect three-dimensional discontinuities and cross-sectional loss in semi-elliptical and round continuous rod strings.  In this paper, the continued development of this new technology and the results from two semi-elliptical continuous rod string scans will be presented. Proposed future enhancements resulting from preliminary field tests will be identified.

When rod pump wells are operated in corrosive environments, corrosion induced sucker rod parts can lead to premature well failure and expensive, repeat workovers. Many corrosion mitigation solutions exist to combat this type of failure, including metallurgy, chemical inhibitor, and epoxy coatings, but they can be costly and not all solutions are appropriate for all types of wells.

In deep wells that require higher tensile rod strength, corrosion friendly metallurgy is generally not an option. In low producing wells, epoxy coatings may not be economically justifiable, depending on lead times and distance from a coating plant. Corrosion inhibitor can require constant monitoring to ensure the treatment is working and not all wells have an environment that promotes an even coating of inhibitor. 

In wells where traditional mitigation techniques have not been effective or economic, RodGuard has been successfully used to reduce the frequency of corrosion-induced rod parts. 
 

Success in the oil and gas industry comes with effectively juggling four key elements: money (made or lost), risk, technical capability, and competition. Information is key to managing this process. Data sharing is the controlled process of providing information to and obtaining information from your competitors in such a manner to ensure your success (and theirs, as well). When well executed, data sharing can help one optimally find and develop highly profitable properties with minimal risk for failure. Unfortunately, poorly executed, the data sharing process can tilt the pursuit in the other direction, as well. This paper was prepared to provide the reader with an understanding of the data sharing process and how to effectively leverage information to succeed in such a competitive and technically challenging environment. There are many data sources available, with varying degrees of cost and value. A great deal of data is available for free from public sources, in a variety of formats. There is also an entire industry made up of companies that, for a fee, provide consistent methods to retrieve public data. They also provide value-added services to validate, scrub, and, sometimes, interpret the data. There are also services to find relevant information or, if necessary, to generate data. Each of these methods incurs some cost, whether it be directly financial, in terms of effort, or risk (due to reliability concerns). A great advantage of these methods is that there is no need to release valuable data to one’s competitors. The disadvantage is that a great deal of valuable information is not available via these avenues. This is where data sharing comes in, from consortia to directly sharing with potential competitors. Data sharing can be extremely valuable, not only in obtaining data but also in developing relationships that build information conduits and can lead to profitable operations that can only be pursued with a partner. While there is considerable value to this approach, there are challenges and hazards that need to be navigated. This paper describes the various methods of retrieving, purchasing, and sharing data and how to utilize data sharing as a mechanism to effectively compete in a challenging environment.

Catastrophic accidents in offshore drilling operations have greatly endangered human lives, environment and capital assets. Although risks in offshore oil and gas operations cannot be completely eliminated, a substantial amount of risks can be minimized through preventive and mitigative measures. A key aspect of the offshore drilling risk is the reliability of drilling systems. According to the World Offshore Accident Dataset and many other investigations, the overwhelming majority of disastrous accidents in offshore drilling operations were caused by equipment failures and human errors. The capabilities to predict the lifetime and provide early and effective warnings in real time are crucial to ensure reliable and safe offshore operations. The objective of this research is to mitigate offshore drilling risks by developing a scientific framework for data-driven failure prognosis for complex drilling systems operating in heterogeneous and extremely harsh environments. A novel data-driven reliability model in conjunction with a systems and economic impact analysis is developed integrating multi-source (e.g., operations and maintenance records, in-situ monitoring data) and multi-modal (e.g., lifetime data, degradation profiles) data. Numerical cases studies will be presented to demonstrate the proposed method. 
 

In a reciprocating rod lift application, production tubing failure due to metal-to-metal contact with sucker rod couplings is a common problem in the highly deviated sections of the tubing string. The coupling is forced to be the point of contact against the tubing wall, which causes high friction and excessive tubing wear during the reciprocating motion. This excessive tubing wear typically leads to a hole in the tubing wall, resulting in high workover costs for the producer.  The coupling surface hardness, roughness, and coefficient of friction between the coupling and the tubing are all directly related to the resulting tubing wear generated at the contact region.  This paper intends to show through both in-house laboratory testing and preliminary field results that applying a lower friction coating to a sucker rod coupling decreases tubing wear and increases the life of the string. 

Problem being addressed: Determining optimized Gas Injection Rate for Gas Lifted wells to maximize lift efficiency. Challenges: While Gas Lift is the most natural artificial lift method, ever-changing surface and downhole conditions cause significant inefficiencies. The changing conditions require frequent adjustments to surface-injected gas rates to maintain the most efficient lifting gradient. If the proper adjustments are not made, these inefficiencies may hinder production and increase lease operating expenses. Solution: By using Apergy’s proprietary hunting algorithm, Bloodhound, optimal gas injections rates are determined by the magnitude in the bottom hole pressure drawdown, with use of a permeant down hole gauge. Through continuous and proportional rate adjustment, the Bloodhound algorithm learns from previous set point deltas and tests against the inferred optimal rate, as well as changing conditions. Results: In under-injection scenarios, Bloodhound can accelerate the recovery of oil by up to 10 percent, regardless of the well’s position on its natural decline. In over-injecting scenarios, wells can maintain oil production rates while using up to 50 percent lift gas. Both results can be successfully achieved with few engineering hours, manually calculating or modeling well performance curves to determine inferred optimal rate. 
 

A hydrodynamic analysis for different rod guide designs simulating downhole fluid conditions was made using computational fluid dynamics (CFD) analysis, which is widely used for solving the partial differential equations of fluid motion by discrete approximation.  A particular turbulence kinetic energy graphic for each guide sample was created and compared to each other. The results shows a significant difference between the samples and the new rod guide design with conclusive proof of a better hydrodynamic performance. 

Dog Leg Severity (DLS) had been used for many decades as recommendations to try to drill oil and gas wells and provide "trouble free" operating conditions. Many of these recommendations were historically based on vertical, shallow (<5000 ft.) deep wells. But as wells continued to be drilled deeper, the recommendations were still applied. With the current drilling and operating practices of deviated and/or horizontal wells, these recommendations may no longer be applicable. Additionally, the deviation measurement interval (degrees/100 ft.) also may no longer be accurate when trying to match downhole problems using existing rod string design software. Furthermore, as wells have become deeper and many now also exclusively are drilled as deviated/ horizontal, side loading (SL) may be a more appropriate condition to be used to determine problems. This paper will review the historic DLS recommendations, provide insight on deviation measurement interval, discuss the importance of SL, and provide new recommendations for drilling wells that should provide better, longer term, less problematic operating wells.