This is a discussion of a newly developed and field tested system to measure and track fluids produced in the oilfield.  The system’s mission is to track the fluid movement from the cradle to the grave and is, for the most part, a “hands off-no humans needed” custody scheme that provides precise verifiable electronic information to the producer, the trucking company that hauls the fluids, and the companies that handle the final deposition of the fluids, either at the disposal well or the pipeline terminal. 

The discussion centers on a West Texas well where the use of this system saves over $10,000 per year in operating costs.  The paper discloses patented technology as well as how the implementation process evolved and overcame the paradigms and mindsets of the people and companies.  Developing new technology is cake walk when compared to altering the complexity of the “oilfield thought” process.
 

Two widely used methods of artificial lift are Electrical Submersible Pumps (ESP) and Sucker Rod Pumps (SRP. Each of these methods frequently require methods to avoid or handle gas for successful operations. Presented here are discussions of methods of gas separation for each method and graphical techniques for prediction of the gas separator performance that will allow the user to better select a workable gas separator system and predict maximum well drawdown with the selected method of lift. 
 

Automation is a crucial element to modern production facilities in the Permian Basin.  However, most facilities engineers lack basic understanding of automation and therefore cannot properly design or implement an automated system.  This paper will discuss automation and instrumentation basics as part of a broad automation philosophy to help readers understand how individual components fit into a complete design.  Individual components (or instruments) will be examined to share what options are available to industry and how they can best be utilized.  An analysis of four common field development scenarios will help facilities engineers grow their knowledge and be better prepared to implement automation into their facilities.
 

One requirement of a Class VI Underground Injection Control permit involves continuous monitoring and reporting of injection pressure. Wells in pilot and commercial scale carbon dioxide (CO2) storage sites are equipped with devices that measure pressure and flow rate during injection operations. Downhole device failures have occured during CO2 injection operations in projects, which prevent bottom hole pressure measurement and require time consuming repairs. A model that can be used to accurately predict bottom hole pressures, based on tubing flow performance, during CO2 injection is warranted. 

This paper uses a two-phase flow model, based on Hagedorn-Brown correlation that uses wellbore parameters and correlated CO2 properties to predict bottom hole pressures during injection. A finite-difference program that uses CO2 density and viscosity, wellhead temperature and pressure, bottom hole temperature, tubing diameter, roughness, well length, and injection rate as input to the model was developed for calculating vertical wellbore pressure changes during injection. Input parameters that have some effect on results are presented and discussed.

The program was applied to field injection data from the Illinois Basin Decatur Project and Industrial Carbon Capture and Sequestration projects to evaluate predicting measured bottom hole pressure data.  The predictions matched measured bottom hole pressure within  (average relative error). 

In the past 10 years, drilling methods have drastically reduced the time it takes to drill wells. This is especially true in today’s unconventional shale market where 20,000 ft wells are being drilled in under 14 days. This increase in drilling rates along with increasing depths and deviations has presented many challenges for the conventional rod lift system, which was designed to last for ten years but are now having issues within the first twenty-four months resulting in substantial increases in workover costs. Below we will review the field test results from a downhole sensor that has been developed and is patent-pending which will measure the forces on the rod system and begin the process of optimizing the life of the rod string through analysis of the downhole forces. An additional benefit is that operators and service companies can now verify the effectiveness of new and existing technologies (rod guides, friction reducers…) in extending the life of the system The downhole sucker sensor can be positioned anywhere in the rodstring and collects measured data for pressure, temperature, torque, tension and compression, velocity and position. Using these measurements, a downhole (actual) Dynacard can be generated to remove the guesswork. These measurements are then used to calculate values for specific gravity, pump fillage and pump intake pressure in order to better understand what is actually happening in today’s unconventional shales. The main objectives are summarized as follows: o Comparing actual Downhole DYNACARD measurements to the Surface and the Predicted Cards o Maximizing reservoir drainage and production optimization o Identifying, isolating and optimizing mechanical issues in problem wells o Measuring the impact of new and existing technologies (such as guides, friction reducers, …) and their effectiveness in extending the service life of the SR system.  Can verify if guides. friction reducers… are adding value and not just cost! 
 

Many sucker rod lifted wells are operating at less than 30% electrical efficiency, because the downhole gas separator installed in the well is inefficient.  Free gas interfering with liquid filling the pump is a major operational problem encountered in producing Sucker Rod Lifted wells.  Gas interference is when free gas at the pump intake enters the pump filling displacement volume with gas in place of liquid, then significant loss in liquid production, reduced drawdown, increased failures and inefficiency occurs.  Installing an incorrectly designed gas separator is the most common problem.  Installing very long separators does not increase separator capacity or efficiency.  Restrictions in the annulus above the pump intake such as tubing anchors result in reduced annular gas flow with gas preferentially entering the pump.  A downhole gas separator has a maximum liquid capacity.  Casing size restricts the maximum size gas separator that can be installed in a well.  The separator used in a well should be designed for the well configuration/conditions.  Gas Separators with high separation efficiency should be used to effectively produce sucker rod lifted wells.

The pump stroke can be longer than the surface stroke when the dynamic motion of the beam pump system adds momentum to the rod string, resulting in the pump stroke length increasing.  The pump stroke can be shorter than the surface stroke when sucker rods stretch to pick up the pump fluid load and other frictional forces.  Rod stretch creates under travel dynamometer card shape.  Pumping fast or high plunger velocities creates over travel cards. 

Pump position in the barrel changes when the pump is not full compared to a stroke when the pump is filled with liquid.  When incomplete pump fillage occurs, the plunger tends to over travels on the down stroke moving deeper into the barrel.  In some cases tagging can occur due to pump spacing, plus increased over travel.  This paper will use field collected dynamometer data to show excessive over-travel can occur on both the upstroke and the down stroke.  
 

Deviated wells have now been the standard form of drilling, increasing well life and production but also creating challenges in the Artificial Lift System, specifically the Reciprocating Rod Lift (RRL). With aggressive drilling deviations rod string guiding becomes a requirement, landing pumps in 45+° zones a normal, and gas mitigation a complete necessity to achieve target productions. 

In 2018, An operator in the MidCon introduced RRL systems to their wells; these (7,000ft) deviated wells utilize conventional pumping units (640 / 912 / 1280’s) and mid-strength sucker rods as the rod of choice. Since then several failures have been observed in the pump, tubing and most frequently in the sucker rod string which have been fatigue related with corrosion and compression as attributing factors to the break.

Over the past 3 years, the Weatherford team has worked together to optimize the well designs based on past failure history observed. This paper will discuss the challenges observed, actions taken, and positive results which have minimized the failure frequencies significantly.   
 

Corrosion fatigue (CF) is an important concern for structures that are exposed to cyclic loads in corrosive environments, especially in the case of oil and gas operations like drilling, offshore risers or sucker rods in artificial lift. Considering the current combination of complex wells completions and the increase of water cuts, the CO2, H2S and Bacteria represent a higher risk for CF failures in sucker rods. This combined effect force operators to choose a steel for either corrosive environments or high loads and increase the chemical inhibition programs.

In response to the new downhole challenges, a research and development program (R&D) has been created to analyze the key factors that affect sucker rods performance under CF. As a result of this R&D program, a new corrosion-fatigue resistance sucker rod has been developed. The present paper summarizes the development process, the new sucker rod characteristics and its performance.

Longer laterals, better perforations and larger frac jobs have all enabled increased production capabilities, yet production optimization practices have remained stagnant and, in doing so, limit the ability to draw wells down more aggressively. The data provided in the most common fluid level processes does not meet the challenges generated by fluctuating well dynamics and conditions. The irregularity and inconsistency of current fluid level measurement systems provide an incomplete snapshot of the well conditions when a more complete solution is needed for optimization. With a permanent, automated fluid level system, reservoir and fluid data is continuously attained. By utilizing a permanent, automated fluid level system located at the well head, the frequency of casing pressure buildups, acoustic velocity shots and fluid level shots data can be drastically increased. Doing so allows for more accuracy in data for pump intake pressure, produced gas up casing, fluid gradient and gas-free fluid levels on rod pumped wells. Paired with properly-tuned algorithms and current optimization practices, these data points give a clearer and more complete story of what rod pumped wells experience continuously throughout the day. Additionally, more information about the reservoir is produced than previously available. This paper aims to introduce the GreenShot, how it works, and what it provides to the operator as well as present case study results that show the production improvements supplied utilizing GreenShot while depicting robustness and accuracy. 
 

The most common well profiles for reciprocating rod lift applications are deviated and highly corrosive wells. Many newly drilled horizontal wells exhibit moderate to severe deviations which require the pump to be set in the curve to produce intended target zones; resulting in a challenging environment for rod lift systems to successfully operate. These wells tend to be accompanied by corrosion, furthering the possibility of premature failures on all downhole equipment: rods, tubing, and pumps. 

Several companies have worked to find a solution to these problems, with one simple product seemingly leading the way, continuous rod. In many wells such as these, continuous rod has proven time and time again that it can improve run life, reduce failures, and optimize production. Continuous rod has recently gone one step further by adding an epoxy coating to resolve the corrosion problem. Several wells have been field trialed and have shown great improvements. This paper will provide an overview of the technology and the field improvements observed up to now.
 

This paper will discuss reducing failures in rod pumped wells by using best practices and design changes. The theme of the paper is to share solutions observed over the last 41 years while working with rod pumped wells. These best practices applied from the polished rod through the bottom hole assembly have been proven to improve run time between failures. The topics discussed are improper installation of equipment along with the effect of a properly designed bottom hole assembly. I will also highlight pump designs and accessory items to help with sand and gas issues. When you lower your failure frequency you are reducing exposure to potential accidents benefiting us all.

Production challenges in horizontal wells are caused by slug flow behaviour from the horizontal. In response, Production Plus developed the flow conditioning HEAL System to mitigate slug flow before fluids enter the downhole separator and pump. Slug flow mitigation allows rod pumping to be more effective and efficient, offering a solution for low-cost OPEX to reliably maximize drawdown.

This paper analyzes multiple HEAL System installations in the Permian Basin that transition from gas lifting to HEAL System rod pumping. It explores requirements for intermediate artificial lift systems, challenges achieving production forecasts, slug flow and solids production mechanisms, and impact from horizontal trajectories.  The discussion compares recent long-term, multiple case studies that statistically demonstrate the impact of flow conditioning on well production economics. It offers insights into long-term NPV benefits achieved by transitioning from gas lifting to the HEAL System with rod pumping.

Evolution of annular gas lift candidates and early results of application in the Delaware Basin. 

Corrosion and fatigue are the primary causes of sucker rod failures in artificial lift systems. Harsh well fluid conditions lead to material loss and detrimental pitting which then lead to initiation points for fatigue fractures to occur.

Production in aggressive service environments with higher acid gas concentrations associated with increased levels of hydrogen sulfide (H2S) and carbon dioxide (CO2) requires good fatigue life associated with corrosion resistance. 

Manufacturers have therefore been challenged to improve products in order to provide reliable technology to overcome industry needs extending production feasibility as long as possible. 

High Strength Low Alloy (HSLA) steels have been widely used in decades to provide fatigue resistance, however the corrosion resistance of such steels is of concern. High-chromium steels have recently been utilized to improve performance, but their corrosion resistance is limited along with their fatigue performance. The development of a true martensitic stainless-steel grade aims to improve corrosion resistance, extend fatigue life of sucker rods and reduce overall operating costs. 

This paper presents the development of a true stainless-steel chemistry with field performance in successful applications throughout Permian Basin and Bakken.

One of the most misunderstood issues in sucker rod pumping is tubing back pressure. The great majority of wells that I have encountered in various fields have back pressure valves installed on the tubing side of a wellhead. However, a great many field personnel do not understand why back pressure is applied, how much to apply, and/or how it affects a well’s performance. This paper will discuss the why, when, and how tubing back pressure is applied along with some misunderstandings and issues of its application. 

This session will explore and introduce a hydraulic drive and transmission system harnessing natural gas engines, to achieve variable speed control, regardless of the power infrastructure available at the well site. 

When paired with an automatic Pump-Off Control system and a De-Gas Compressor, which is available with a dual drive transmission option, the patented hydraulic drive system eliminates the need/ cost of electricity at the well site, achieves lower operating costs, and optimizes production by as much as 40%.

This interactive session will encourage producers to discuss how harnessing natural gas to power pumping units will make a positive impact on their new and existing well sites.

Production engineers rely upon a variety of data streams from the field to optimize production and maintain safe, environmentally responsible operations; without the reliable collection of this information, we cannot do our jobs. Given the challenges of operating assets spread over vast areas and the inadequacies of workflows relying upon manual measurements and communication, automated data gathering and telemetry have long been key focuses in the industry. Today, SCADA systems are the established standard to address those issues. They also interface with industrial controllers that allow operators to acquire data and take remote actions. 

However, they suffer from severe drawbacks: mediocre data resolution and integrity, high implementation costs and complexity as well as siloed data streams leading most information to be lost or stranded on the field. This leads to major friction in the widespread roll-out of automation systems, which are typically only installed on high production assets, and often underutilized due to their excessive complexity. Low data resolution and overall quality also turn out to be major impediments to the feasibility of higher value-added data science use cases such as predictive maintenance. The primary cause of this situation is that these systems remain largely insulated from the trail blazing developments in more open-source technologies that have been fostered by the development of widespread internet services and consumer electronics. 

In this presentation, we introduce state-of-the-art developments in terms of hardware and computing technologies that leverage those advances to allow low friction, turnkey, high-resolution data collection and field automation. These are combined with novel automated processing frameworks that provide high value insights without drowning users in impractical amounts of data. Ultimately, we show how these developments effectively leverage data points across the field to (1) reduce the cost of monitoring assets by an order of magnitude, (2) remove the need for routine in-person inspections of leases, and (3) increase production and equipment lifetime while reducing power consumption through optimization. 

The efficiency of most artificial lift systems is reduced significantly whenever the tubing and the annulus are in communication due to the presence of unwanted holes or leaks developed in some of the hardware used in the installation. Detection of the problem from analysis production records must be followed with field tests that verify the diagnostic before proceeding with repair operations. 

Conventional single-shot acoustic fluid level measurements have been used in the past, using special procedures, to generate acoustic records that in the presence of tubing-casing holes may exhibit anomalies that point to the location of the hole or leak.
 
This paper describes a new, advanced user-friendly system that allows simultaneous acquisition of dual acoustic records, one via the tubing and one via the annulus, using wireless sensors for easy and efficient installation. The procedures for acquiring the data and the latest software tools used for the analysis to verify the presence of the hole and locate its position within the wellbore are discussed in detail. Several field examples of measurements performed in Gas Lift and Plunger Lift wells are presented to illustrate the new application.

Given several pumping cycles worth of surface card data, the dv8 advanced diagnostics model is solved and the rod displacements, axial loads and sideloads are calculated, starting from the polished rod and propagating to the pump. From the axial load, the rod stress is computed. The points along the rod string are then analyzed using a modified Goodman diagram applicable to the type of rod string used. The maximum stress experienced by the rod is compared to the maximum allowable stress to determine if the rod string is overloaded. Review of case studies and results are published.

Gas lift is long known to be an effective and versatile form of artificial lift and is widely used in oil and gas production. The gas lift process is dependent on gas pressures not naturally available from oil and gas production facilities. Rather gas must be pressurized through use of a compressor and thus compressors are a vital component to the gas lift process. Unfortunately, some operators have experienced unsatisfactory levels of compressor runtime, particularly during periods of cold weather. When the compressor is down, well production suffers. Thus, some operators have turned away from gas lift as a viable production method over concerns with compressor reliability. This is unfortunate and demands education on compressor design and operation strategies to increase compressor runtime, especially during cold weather operations. This paper addresses the key factors that impact compressor runtime during periods of cold weather and offers insight as to how to increase the reliability of gas lift system.

Gas and solid separation continue to be a significant challenge for operators. Gas interference causes unnecessary shutdowns in rod pumped wells, leading to difficult pumping conditions and lost production. Additionally, damage from solid abrasions leads to mechanically-incurred erosion failures. 

With a well-designed Bottom Hole Assembly (BHA), downtime as well as gas and solids passing through the pump can be minimized. 

To increase production, industry standards call for operators to maximize separation area while taking downward fluid velocity into consideration. The less gas passed through the pump equates to fewer gas interference or pump off cards and therefore increased drawdown. 

An appropriately designed BHA avoids unnecessary shutdowns and enables stabilized pump fillage, decreased Gas to Liquid Ratio (GLR) and better reservoir drawdown. 

By achieving proper gas and solid mitigation, operators are allowed more freedom in pumping practices with or without lowering the pump in the curve and overall profitability is increased. Operator data showing the impact of this new technology will be presented. 

Design and analysis of sucker rod systems in deviated wells has challenged industry practitioners. Historical adaptations of the wave equation solution struggle with 3-dimensional wellbore trajectories and other system complexities. A unique finite element model, embodied in an easy-to-use software, simulates rod-dynamics in 3 dimensions. The model can predict or analyze motion of the rod string at any location in the well. Frictional forces and buckling tendencies are also simulated. This advanced computer software also provides a sophisticated, interactive visualization of simulation results. Through superior modeling, sucker rod system design and operating parameters can be optimized to reduce mechanical wear and component failures.

Slow strokes per minute, open pump clearances in a deep well have impacted the shape of the pump card and frequently results in the question: "Is my tubing unanchored?".  The Coefficient of Tubing Stretch, Kt, and the downhole pump dynamometer card can be used to help identify unanchored tubing.  The Unanchored Kt and Anchored Kt lines plotted on the left side of the pump card shape are the first step in resolving if tubing is anchored.

Excessive mechanical friction from doglegs created when drilling the well in the upper section of the wellbore can result in erroneous load measurement when initially setting the tubing anchor.  Setting a tubing anchor should be done by pulling inches of stretch and should not be done using a load measurement gage.

Slippage and/or a leaky pump can make identifying unanchored tubing difficult, because the left side of the pump card dynamometer card leans to the right in a similar fashion as unanchored tubing. A static traveling valve load test is a common field technique to determine if a leaky pump is present.  The Patterson Slippage equation was developed to calculate pump slippage for the entire stroke. If a portion of the Patterson slippage can be allocated to the left side of the pump card stroke, where the fluid load is transferred from the tubing to the sucker rods; then a pump slippage line could be plotted and be used as an additional aid in identifying slippage plus anchored or unanchored tubing.

 Understand if my tubing anchor is properly set is important in long sucker rod and tubing run life.  This paper will use many examples pump cards acquired from various sucker rod lifted wells to explain if tubing is unanchored or does the pump card shows tubing movement, unanchored tubing, excessive slippage or does this shape show this some other issue.

The effect of traditional chemical treatments at the pump intake can be minimized due to the fluid level, high GLR, and production packers, among other reasons. Using a slow-release polymer matrix is an effective chemical treatment that was installed in several wells in the Delaware basin with Conoco Phillips. The chemicals were encapsulated in the matrix ensuring maximum absorption and then slow dispersion, and the tool was run under the intake of rod pumps, and gas lift. In rod pumps, the installations were carried out by pulling the production tubing while in the Gas Lifts, the chemical tools were installed via slickline without pulling the BHA. In the gas lifts and in rod pumps, the chemical tool can be replaced whenever the concentration levels reach the minimum effective concentration without pulling the tubing. To track the dispersion rate, the wells were sampled monthly to measure the concentration of scale and corrosion inhibitor and the amount of THPS downhole. The whole tracking history of the wells will offer valuable information about the chemical concentrations expected using downhole chemical treatment compared with the concentrations obtained while using surface treatments and the longevity of the treatment at the production rates and depths installed.