Chlorine Dioxide (ClO2) has been used as a well damage removal and stimulation fluid since the late 1980’s. It was originally investigated as a means to remediate reservoirs of the permanently damaging effects of polymer, monomer, and polyacrylamide floods popular in the 1980’s across many conventional oilfields, including those in the Permian Basin of West Texas, U.S.A. Chlorine Dioxide is a strong oxidizer and highly effective biocide, very popular today for preparing frac waters and aiding in recycling produced waters, also to be used in fracturing.  Many petroleum engineers and oilfield production personnel are not aware of the chemistry, or services available to remove the damaging effects of polymers, polyacrylamide, frac gel, gel filter cake, biomass / biofilms, Hydrogen Sulfide (H2S), Iron Sulfide (FeS), Iron Oxide (Fe2O3), all species of bacteria including Sulfate Reducing Bacteria (SRB’s), and many other oxidizable particles that have plugged and otherwise damaged all types of wells.  Chlorine Dioxide has proven to be extremely effective in salt water disposal (SWD’s) and injection wells, but has also found an important role in vertical and horizontal producers having production challenges such as Iron Sulfide, due to the infiltration of SRB’s into the reservoir and the subsequent H2S, FeS, and H2S corrosion. This paper forms a summary of the ways Chlorine Dioxide, in conjunction with Hydrochloric acid (HCL), is used to remove wellbore damage, drastically reduce H2S levels, and overall, restore the well’s injectivity or productivity.  In addition, the paper outlines to the key aspects of treatment design to insure success while concentrating on practical field applications, as demonstrated in wells across the Permian Basin.

In the last 10-15 years, the US has seen a remarkable surge in the production of oil and natural gas as the industry learned how to properly complete and produce previously non-productive formations. With this increased hydrocarbon production, we have also seen an increase in the amount of water that is produced and must be managed. The large volumes of water that must be gathered, managed and eventually disposed, along with a growing trend for operators to prioritize their capital spend on drilling and completing revenue-producing wells, has created an opening for midstream water companies dedicated to produced water. While some of this produced water is treated to some degree and then used in ongoing completions to offset an equal volume of fresh water, the majority of it is destined for disposal via Class II UIC wells. Often this produce water has some degree of mineral scale over-saturation, or may be mixed with other waters that may or may not be compatible from a mineral standpoint. The water may contain various quantities of dispersed hydrocarbons, suspended organic material or inorganic solids such as iron sulfide or iron oxide - all of which can potentially impair the ability of the injection well to take water. Last, but not least, bacteria such as acid producing bacteria or sulfate reducing bacteria may be present in the produced water and may cause corrosion issues when allowed to contact bare steel and can generate biomass that again can impair injectivity. This paper will discuss the potential issues with the movement and injection of produced water outlined above. It will also outline and detail the best methods to monitor and analyze for these potential issues, the best approach to correcting or preventing of issues that may impair flow or injectivity and, finally, how to best monitor long-term to document success and properly optimize the preventative treatment program. 
 

A Chemical Management Program is an integral part of an overall effort to reduce downhole and surface failures.  The success of a Chemical Management Program depends upon the Operator and the Chemical vendor understanding the expectations and responsibilities assigned to each party.  This paper identifies the critical tasks associated with a successful program to aid in clarification as to which party is responsible for each.  The terms of the business contract would then be defined around these tasks. 
 

Corrosion enhanced abrasive wear is a common cause of failure in sucker rod systems. The combination of high side loads caused by deviation and the presence of corrosive chemicals creates a very difficult environment for operators. The cyclical loading nature of sucker rod system adds to the problem, leading to premature failures in rods and tubing. Operators are turning to many technologies to increase mean time between failures (MTBF) in these challenging wells. Thermoplastic liners is one of the many options to extend run life in deviated wellbores. Liners are extruded from specialty compounded resins, each with its own set of advantages and disadvantages. A new resin is now 
being extruded to fill the void between 200 and 250 degrees Fahrenheit, allowing operators to maximize the benefit of lined tubing at a more economical price than higher temperature resins. This paper summarizes the properties of the new resin in comparison to the other resins currently on the market.
 

Pertamina Hulu Energi Offshore North West Java (PHE ONWJ), which is a Production Sharing Contractor of the Government of Indonesia, operates a large number of offshore ESP wells in Java Sea, Indonesia. To stimulate the wells and increase near-wellbore permeability, PHE ONWJ has executed matrix acidizing from 2013 until 2015. During acid deployment, ESP was left in place (downhole). In fact, the ESP was also switched on to unload the spent acid. Given the acid corrosive properties on metals which make up some of the ESP components, a post-stimulation evaluation was conducted in May 2016. This paper attempts to analyze the effect of acid jobs on ESP components integrity and field production performance. Afterwards, this paper discusses some approaches that PHE ONWJ believes to be applicable to observe any need for periodical acid job in the field.

Multiphase flow is found in various places both in nature and in practice, however, multiphase flow is prevalent in the petroleum production industry. This phenomenon brings about a major problem of pressure loss in piping systems and results in a loss in production. Multiphase flow has been studied for years however, with the increase in unconventional engineering methods, there is now a greater need for the study of multiphase flow. This study investigates various phenomena created by multiphase flow such as flow patterns known as flow regimes and pressure loss created by friction and different fluid phase properties. An experimental system was designed to represent situations in the oil and gas industry. The system included pipe orientations of horizontal, inclined and vertical sections as experienced during petroleum migration from the reservoir to the surface. To represent multiphase flow in the experimental system, water was used to represent the oil and compressed air to represent gas in the wellbore. The pressure difference throughout the system was the system was calculated using the Beggs and Brill Correlation and the Lockhart Martinelli Parameter. Experimental pressure differences were measured for different parts of the system while observing the flow regimes created by multiphase fluid interaction. Through the research methods, it was found that the majority of the pressure losses occurred in the elbows and most frictional pressure loss occurred in the vertical 3ft pipe while the 45° & 90° downhill pipes had an increase in pressure. 
 

Environmental concerns and increasing costs are creating a need for a polymer that will allow the use of a high salt, high hardness water in the making of a viscosified frac fluid. Any new polymer would also need to tick the boxes for cost, rheology, HS&E characteristics as well as breaking in the reservoir. Past development efforts have focused on improving organic-based polymers. A new approach was taken and a shift was made to the use of silica-based polymer. This paper will review silica chemistry but the focus will be on West Texas field trials where the silica gel was used as an alternative to 20 lb/Mgal crosslinked-guar. Covered topics will include; chemistry of produced water, making the silica gel on-location, pumping characteristics, cost and impact on production.
 

High costs of obtaining fresh water and produced water disposal, as well as low commodity prices have made water reclamation an attractive option for companies looking to increase their profit margins. Special environmental considerations arise when dealing with the handling and treatment of produced and reclaimed fluids for use in oilfield operations. These include the handling of wastes generated from treating large volumes of produced water, storing and transporting the water via properly designed tanks, ponds, pipes, and other equipment, and complying with existing environmental regulations while adequately assessing additional risks associated with water recycling. The paper will discuss the current technologies utilized to treat reclaimed water and the environmental risks associated with them, special facilities design considerations for handling reclaimed water, relevant environmental policies, and the general pros and cons of water recycling including economic factors, infrastructure requirements, and public perceptions.  

A new gas separation technology was released last year with the goal of creating a substantially increased volume capacity and therefore significantly improved separation quality through application of a process known as limited-entry. This process is more commonly applied to well fracturing and other stimulation procedures wherein the principle is applied to create an equal distribution of fluids to be pumped into an expansive length of producing formation or a variety of formation qualities at once. In the Multi-Stage Limited-Entry (MSLE) separator’s design that same principle is utilized, but in a reversed method such that the fluids being ingested into the gas separator are purposefully restricted through the uppermost chamber and thus the remaining volume must then be handled by the next chamber stacked below. This process continues until the entire volume of fluids designed to be pumped from the well are ingested by the separator stack, at the designed slow pace, and pumped through the rod pump BHA then to surface. The most notable benefit of applying this process to gas separation is that it becomes feasible to slow the intake of the gas-laden fluids by an extreme amount; far more than is possible by simply running a much larger OD poor-boy style separator or a much smaller OD packer-style separator. Slowing down the intake of fluids by dividing the work equally into a stacked set of separation chambers allow for a minimum target of 1.0”/second or less fluid drawdown velocity to become possible which is 6 times slower than other separators are designed for and what their claimed capacities are derived from, yet is what will directly drive far greater ability to reach exceptional levels of gas separation quality and, ultimately, far superior rod pumping production and overall operational success. The MSLE separator manipulates the wellbore and fluid intake path such that the historic and only method of increasing separation capacity, adding more dead-space cross-sectional area, is no longer the primary and also limiting means of improving separation performance. There is only a limited amount of room to work with in historic separation options in the typically applied casing sizes of 7” and, more commonly for the Permian Basin, 5.5”. Getting too aggressive with design applications in effort to add dead-space ultimately leads to either extreme annular superficial gas velocity (resulting in fluid blow-by) when applying a large OD poor-boor style separator with tight tolerance to the casing ID or going the other direction, pressure drop inside the flow-through tube (resulting in potential depositions/plugging) when applying a small OD packer-style separator. This paper will explain the process of limited-entry as it applies to gas separation design and how the resultant MSLE separator functions differ in regards to other commonly applied separators. Further, a notable series of MSLE separator tests will be reviewed to illustrate lessons learned, design improvements implemented, and overall performance achieved in a variety of well conditions. 
 

This study is directed toward investigating possible effects of the anisotropy ratio on the analysis and result of buildup tests using Horner method. Even though most reservoirs are more or less homogeneous but not necessarily isotropic, there is no direct method for estimating the anisotropy ratio at reservoir scale despite the fact that this parameter affects to a great extent the reservoir behavior.  
The approach used in this study is to solve numerically the one phase 3-D equations that governs the fluid flow in a reservoir. After checking the solution by simulating a test well under buildup, a parametric study to investigate a possible sensitivity of the results to the anisotropy ratio has been conducted.

A MATLAB computer program using a finite difference approach has been written for this purpose. Buildup tests have been simulated successfully and an estimation of the permeability using Horner analysis showed that the results are consistent with the data used for the simulated reservoir. Even though these preliminary results show that Horner method cannot discern between isotropic and non-isotropic reservoirs for fully penetrating wells, the behavior of partially penetrating wells shows clearly that the anisotropy ratio has a significant effect on the calculated permeability. More specifically, this study shows that the effect of the anisotropy ratio is proportional to the penetration ratio of the partially perforated wells.

These results have been generated by simulating very thick and pretty coarse reservoirs. It is expected that more simulation runs will shed more light on the effect of anisotropy ratio on well behavior during routine well testing procedure.
 

Because the flow regimes and drainage geometry of horizontal well are different from those of vertical wells, there is a need to develop a distinct analytical Productivity Index (PI) solution for horizontal well.  There have been several researches in the early 1990's  developing the solutions; however, each solution generates different PI values.  The degree of disparity depends on how conservative or optimistic the input values are, which possibly results in the reduction in confidence level when applying these analytical methods.  This paper presents a review on the available analytical solutions for horizontal well PI.  In addition, this paper attempts to conduct a comparative study between the analytical solutions an numerical simulation approach to investigate which analytical solution is the most useful and should be utilized with higher confidence level, assuming that the numerical simulation generates more accurate PI values.

Re-utilization of company owned artificial lift equipment and parts is a common practice among operators and service providers across the industry.  It is common practice for operators to resize artificial lift equipment at failure or proactively as economics allow. During resizing activity, it is not uncommon to utilize company owned equipment and inventory to satisfy the hydraulic lifting requirements of the system.

In this paper we share how we leveraged our internal data and along with Q-rod to classify and rank our pumping unit population of over 6000+ wells across our EOR and Unconventional Assets in the Permian Basin. This application was developed using industry standard object-relation database systems, languages, and visualization software. As a result, the project has promoted a company-wide reduction in new purchases of pumping units and motors for the last three years which has supported reducing operating expenses.
 

This paper describes an artificial lift case study where three pilot test wells were installed using measuring-while-installing (MWI) equipment during the process. The final results enabled us to meet the goals and expectations of these test wells. The main test objectives were to reduce the time to run the electrical submersible pump (ESP) in the well, to 
increase the ESP reliability while installing, to monitor the installation with real-time data, and to concurrently monitor rig crew activity. The use of MWI equipment during the ESP installation is a technique that reduces unnecessary manual steps through automation, saving rig time. The technique also reduces HS&E concerns and provides the ability to continuously monitor real-time downhole gauge data such as automated cable conductor resistance measurements and cable integrity. The battery-operated equipment avoids the need for an electrical collector/slip ring system on the spooling unit.

This paper describes the equipment, process and final results after the well tests, where the MWI equipment was used to reduce the installation time by minimizing manual intervention during the electrical tests and to collect real-time data during installation. In addition, results are shared from an economic analysis that demonstrated cost savings achieved from using the MWI equipment compared with other traditional artificial lift installation methods. These results indicate the potential benefits to use this new 
technique and equipment in Permian artificial lift operations.
 

Synthetic Polyphthalamide (PPA) has greater resistance than many plastics to a broad range of chemicals and is widely used in the manufacture of sucker-rod guides when operating at depths where temperatures can reach 300℉ (149℃). However, while rated to 400℉, field experience has shown that under certain conditions, the service life of sucker-rod guides constructed of this material can be adversely affected at depths with temperatures as low as 220℉ in continuous use. After extensive research, followed by nearly two years of field testing, the solution was found: a new type of molded-plastic sucker-rod guide, with a proprietary polyether ether ketone (PEEK) blend. The new PEEK-blend sucker-rod guide is an ideal replacement for synthetic polyamide models in shale wells because PEEK is a thermoplastic that retains its mechanical and chemical-resistance properties even at high temperatures.

Over 70% of the artificially lifted wells in the US are using sucker rod pumping systems. The sucker rod pumping system has been ameliorated during past years due to the high investment of companies and installers as performance of the sucker rod pumping system directly impacts production volume and consequently revenue of E&P companies. The sucker rod is one of the most vulnerable components of a sucker rod pumping system. The correlation between metallurgical variables and mechanical properties is of great importance to ensure proper functionality and to identify rod string optimization opportunities. The API 11B has classified different grades of sucker rods to aid the sucker rod utilization by operators as well as the standards for manufacturers. Corrosiveness of the wellbore fluid, well depths (loads), material susceptibility to H2S related cracking and other conditions are crucial to sucker rod’s continuous manufacturing improvement. A set of secondary or unconventional metallurgical factors have specific effects on mechanical properties that can aid in the sucker rod performance subject to these conditions. These factors are reviewed in this study along with its impact in the selection of suitable sucker rod grades to increase the life of sucker rod pump installations. This paper presents theoretical considerations and testing data to study metallurgical factors that affect the final mechanical properties of API grade sucker rods. Some of the metallurgical and mechanical variables testedand discussed include micro-alloying content, normalizing cooling rates, toughness and residual stresses developed at the steel mill and the sucker rod processing plant. Finally, an economical overview of these metallurgical and mechanical variables on different API grades are also discussed in this study.

Rod pumps with isolated tailpipe systems have been growing in popularity over the past few years and applied in basins all over the US.  Some earlier system component designs had vital shortcomings that became more evident over time with the growing install base.  
The important fact is that these lessons learned have been a driving force in making positive strides to improve installation procedures, component design, and material selections.  Another vital element leading to improved consistencies and better results is an accelerated and expanded knowledge regarding the required nodal analysis to properly predict required production and reservoir properties to yield optimal system function. 

This paper will cover the process that has been endured to get to the current improved state of operations and how further success is assumed to be obtained as rod pumps with isolated tailpipes are applied in unconventional wells for years to come. 
 

A casing gas separator (CGS) is a safe to run, low-risk, and efficiency altering tool that pairs naturally with existing wellbore design and work practices to vastly improve gas handling and capacity in virtually any form of artificial lift.

When a new well is drilled the hole is cased and cemented and during that process a CGS is run permanently into place on the casing with no alteration to the drilling program whatsoever.  The CGS is commonly placed at kickoff point or in a tangent further downhole and well work occurs with absolutely no alteration to normal completion processes.  

A CGS may be run and set with multiple flowpath options and separation capacity is essentially doubled by providing twice the casing flow area inside the tool.  The result is the most prolific and flexible gas separation technology any horizontal well has ever applied. 
 

Relating Polished Rod Velocity and ratio of MPRL/PPRL to Failure Frequency. This study uses historical data to understand these relationships. The data is primarily from San Andres and Clearfork water floods and CO2 floods located in the Permian Basin.

Historically as many as 30% of bottom hold down pumps have been stuck. This can result in extra cost associated with pulling tubing on pump repairs or rod failures. This paper focuses on efforts with various tools and techniques that have been used to lessen the number of pumps stuck in tubing.

New unconventional wells have been a huge challenge for ESPs in the Permian Basin because in horizontal wells with high-formation GORs or GLRs, the pumped fluid can cause issues such as gas interference, gas locking, short run life, low production, poor energy efficiency, increased failure rates, shutdowns, so forth. A major problem is gas presence around the ESPs, it causes the motor to rapidly overheat because the gas is incapable of adequately cooling.

For this application, a double stage of gas separation was designed to break the gas slug and avoid gas entrance into ESPs by forcing free gas to go around the shroud and produce through the casing, and the fluid is forced to pass through an additional gas separator (Guardian Shield), this tool helps to separate gas to keep lower motor temperature. These novel applications help operators to reduced OPEX (operating expense) by minimize well Interventions, decreasing failures in the pump due to overheat, and allow the ESP to operate in gassy wells with high GLR, stabilizing the production and reduce the unforeseen interruption.
 

Pumping wells hard involves a tradeoff between operating cost and production. Increased idle time or holding additional back pressure on the reservoir can decrease production but pumping a well harder will likely increase failure frequency. The existing reservoir pressure has a significant impact on the potential change in production.  Pump-Off Controllers (POCs) are used to regulate run time on many wells operated in Permian Basin water floods and are accepted as a failure reducing and cost saving tool. Moving set points in, changing the pump off strokes, and decreasing SPM should not affect production. Notably, conventional inflow models demonstrate that reductions in flowing bottom-hole pressure become less impactful when wells are operated at relatively low bottom-hole pressures. This paper will discuss specific examples of using POCs to pump wells gently and illustrate one mythology or calculator to evaluate the economic tradeoff.

Producers are continuously challenged to keep drilling costs as low as possible and retain operational flexibility so as not to compromise completion and production performance. Well construction cost reduction strategies that include a casing size reduction can cause long-term production inefficiencies. Smaller casing sizes impact the critical liquid lifting velocity necessary to support efficient artificial lift thereby compromising production. If during the lifting phase, critical liquid lifting velocities are exceeded in the production annulus above the downhole pump, the producing bottomhole pressures become higher, and the producing rates consequently lower.  Preventing the risk of critical liquid lifting velocities in the production annulus maximizes drawdown and production.

This paper demonstrates a low risk, cost-effective modification to a standard 5 ½ inch monobore casing design can effectively control critical liquid lifting velocities occurring during the production lifting phase. The paper shows and analyze field studies from Producer’s currently implementing this approach.
 

Downhole sucker rod pump clearance changes from shop conditions to bottom hole conditions due to bottomhole pressure and temperature that the pump components are subjected to. Presented here are equations to estimate the change in dimensions of the plunger and barrel of top and bottom hold down pumps at bottomhole pressure and temperature conditions. The approach uses one equation for cylinder dimension changes with pressure with appropriate inputs for the internal and external pressure (or average pressure) for the upstroke when slippage is important and has an effect on the total production.  Examples are given for thin and heavy wall pumps at a variety of depths, pressures, and temperatures. Corresponding production rates for the calculated downhole pump dimensions are given.

Rod wear and corrosion have a complex relationship that is often misunderstood of oversimplified.  This paper provides a technical framework and provides empirical evidence of principles that clarify this complex relationship.  In particular, this paper will review stress levels and metal failure mechanisms that dispel many commonly held beliefs.  A better understanding of these principles will lead to opportunities to reduce an operator’s total operating footprint.

Automation of rod pumping systems has been a part of the oil and gas industry for over 65 years.  Starting with time clocks in the 1950s, the invention of the pump-off controller in the 60s, and variable speed drives in the early 2000s, the amount of technology available to both control and analyze the system has increased and improved drastically. Several of the driving factors to automate include high initial production rates, followed by a steep decline, gas slugging, high degrees of rod and tubing friction, and paraffin build.  This paper will detail several of the automation packages and features that are available on the current market, the applications of each feature, and how they can be beneficial in preventing premature failures of the main components involved in a rod lift system.