Fifty-six waterflood projects are grouped according to the producing water-oil ratios (WOR) in effect at the start of polymer treatment. A relationship between barrels of polymer oil, amount of polymer and water-oil ratio is developed over a range of WOR's from 1 to 50. Projects singled out for special study include conglomerate, sand, lime and fractured reservoirs. Hall Plots and input profile surveys are used to show injection side changes due to polymer treatment. Oil recovery/WOR curves and time/rate graphs illustrate production side responses. In all cases the polymer treatment was designed to improve volumetric sweep of the reservoir.

You are working on a problem that has been my problem for nearly 40 years

Drilling practices have changed considerably through the years. When rotary drilling first started, drill collars (as we know them today) were unheard of. Bits were not designed for heavy loads and only the weight of the drill pipe with a crossover sub (called a collar) between the drill pipe and bit, supplied the drilling weight. The search for more hydrocarbons required penetration of deeper and harder formations and brought about the development of improved rotary bits with the need for additional weight to make the bit drill. In an effort to put more weight on the bit, additional drill pipe weight was slacked off putting more drill pipe in compression. This resulted in an increased number of drill pipe failures. It was discovered that when drill pipe is run in compression for bit weight, it buckles and is subject to severe bending fatigue resulting in these failures. This is due to the stress reversals in the thin wall of the drill pipe created by rotating the pipe in compression while it is bent. Using this theory another person developed the idea of using heavy thick-walled pipe between the bit and drill pipe to furnish the necessary weight for the bit. These joints of heavy thick-walled pipe were called drill collars, named after the crossover sub that had been used in the same position in the string. Only a few collars were used initially, but the quantity increased rapidly with improved bit design and deeper drilling. Very few problems were encountered when only six to nine drill collars were used; but connection failures increased rapidly with the running of additional collars, because the drill collars buckled under the additional drill collar weight. Drill collars differ from drill pipe in that the highest points of stress are in the connection, due to the tube or body being much stiffer and stronger than the connection. The use of special bottomhole assemblies to centralize the collars and stiffen the connections was unheard of at this time. Initially, not much thought was given to deviation. It was believed that if the kelly were held straight up and down in starting the hole, it would continue straight. No one realized holes were being drilled crooked until the development of the Seminole Field in Oklahoma in about 1928 and 1929. People started to be suspicious when some wells required considerably more footage of casing to complete than others. Since the wells were assumed to be in the same producing horizon, the geologists were confused. It wasn"t until two offset drilling wells actually intersected one another, causing numerous fishing jobs, that people realized that crooked holes were possible. They began to be concerned about the cost of the additional tubing and casing to complete these crooked holes, and deviation from vertical became an important factor in the drilling industry. It was at this time that the acid bottle came into use as a means of measuring the hole inclination from vertical. A bottle of hydrofluoric acid was lowered into the well on a line and allowed to sit long enough for the acid to etch the inside of the bottle. This wasn"t very accurate, but the approximate deviation from vertical could be determined.

Water quality is becoming a larger issue for the producer, as water production increases. Poor water quality in injection water can create plugging and loss of injectivity. It also can result in a loss of revenue due to re-injection of hydrocarbons. This paper will discuss issues of water quality. It will also detail how to develop effective monitoring locations and how to interpret results of water quality tests to determine effective treatment. Examples of actual production data will be provided to illustrate how improving water quality will result in increased revenue to the producer.

The counterbalance problem is one of application, which is caused by the lack of knowledge on the part of the operating personnel as to the importance of proper counterbalance, and/or a program to assure proper application of this counterbalance. Further, the problem and need is present in each beam type sucker rod pumping system. The magnitude of these problems are realized when you consider that in excess of 80% of the world's pumping systems are of the beam type. Eventually, each person concerned with production of oil will be forced by necessity to solve in some manner his individual needs in relation to counterbalance.

In 1998, employees of Exxon (ExxonMobil after November 30, 1999) in partnership with Trout Unlimited, the Wildlife Habitat Council and the Boy Scouts of America, constructed a pond habitat project in western Wyoming. This voluntary environmental project augments efforts by the Wyoming Game and Fish Department to stabilize native Colorado River Cutthroat Trout populations and is comprised of a deep pond that provides trout overwintering and rearing habitat. The project demonstrates responsible corporate environmental performance and will be used to promote balanced environmental education and to foster cooperative relationships with state and federal regulatory agencies. This project reflects the pride and enthusiasm that ExxonMobil employees have for the communities and states where the company does business, and serves as an example of the progress that can be achieved when neighbors join together in a common effort to enhance environment values. The Sawmill Creek Trout Recovery Project received the Oil and Gas Reclamation and Wildlife Stewardship award from the Wyoming Game and Fish Department in September 1999. The project also received recognition in November 1999 from the Wildlife Habitat Council as a Certified Corporate Wildlife Habitat Site.

The purpose of this paper is to answer the ten most asked questions about plunger lift. 1. Do I Have Enough Pressure? 2. Do I Have Enough Gas Volume? 3. Will It Run Under A Packer? 4. Is My Sales Line Pressure Too High? 5. What Is My Operating And Maintenance Cost? 6. How Long Will It Be Effective? 7. Will It Work With Gas Lift? 8. Will It Work In Paraffin? 9. How Much Improvement Can Be Expected? 10. Will I Eventually Need A Pumping Unit? From these ten questions we can identify the areas of interest as Identifying a Candidate, Operating Cost and Economics and will answer the questions in those areas

This paper describes the automation system installed at the ARC0 Permian operated, Willard Unit CO2 flood. The automation includes a Supervisory Control and Data Acquisition (SCADA) system for pump off control, shutdowns and safety/environmental monitoring of over 300 rod pumped and flowing wells. The 24 hour monitoring system along with the data obtained, provides the benefit for identifying potential well problems and quick operator response. The paper also details the customization of the operator interface.

An extensive stimulation program is in progress in the San Andres Formation in the Willard Unit, Wasson Field, Texas. This paper presents some of the problems involved in the design and execution of the hydraulic fracturing operations. The case histories of two of these wells are presented.

This paper presents statistics for remedial stimulation work performed at the Willard Unit since 1986. It also discloses how stimulation candidates are chosen, what stimulation fluids are used at present, and how stimulation work is tracked. The Willard Unit is a San Andres carbon-dioxide flood located in the north-central portion of the Wasson field near Denver City, Texas. The Unit produced under primary from the mid 1930's until the start of water-flood operations in the mid 1960"s. Tertiary operations commenced in 1985 with the injection of carbon dioxide into approximately two thirds of the unit which is comprised of 340 producers and 260 injectors. The San Andres at the Willard Unit is a dolomite found at a depth of about 5100". Gross pay averages 150", porosity averages 8.5%, and permeability averages 1.5 md. The majority of wells are cased to 1 D and perforated with 15 to 20 holes. Producers have been sand fractured, and injectors have been either sand fractured or gelled-acid fractured.

Magnetic Flux density (MFD) technology is a safe and accurate means of locating and monitoring variations within the body wall of tubing and casing products. Older technology utilizing Gamma Radiation to identify these problems is very hazardous, typically produces limited results, and is physically limited to effectively evaluating only 6% to 12% of the total tube body. Improved MFD technology can offer a safe and effective method to evaluate 100% of the tube body for wall loss from corrosion, tool cuts, and sucker rod wear.

The complexity and cost of exploring for oil and gas has increased significantly in the past few years due to Intelligent Wells, Multilaterals and Heavy Oil field developments. New challenges for drilling, completing, producing, intervening in a well, environmental regulations, and wide swings in the price of oil have changed the role of technology in the oil fields. The industry is relying on technology to affect the costs of exploring for hydrocarbons in the following ways: - Reduce operating expenses (OPEX) by automating the processes used to explore and produce hydro - lncrease net present value (NPV) by providing systems that enhance the recovery of hydrocarbons f carbons, reducing the frequency of unplanned intervention, and improving information and knowledge management to decrease operating inefficiencies. From reservoirs. The new technologies improve production techniques to delay and/or reduce the production of water from downhole drilled and that will reduce the number of surface facilities required. The surface equipment requirements to handle increasingly larger quantities of hydrocarbons at these facilities should also decrease with the implementation of new technologies. - Reduce capital expenditures (CAPEX) by creating processes that will decrease the number of wells New processes for drilling, completion, production, artificial lift, and reservoir management have been created by advancements in technology in fields such as high temperature sensory, downhole navigation systems, composite materials, computer processing speed and power, software management, knowledge gathering and processing, communications and power management. Horizontal drilling and new fracture techniques have allowed operators to produce hydrocarbons profitably from areas that were uneconomical just a few years ago. Sensor technology in conjunction with data communications techniques provide on-demand access to the information necessary to optimize hydrocarbon production levels and achieve costs goals. Surface and downhole sensors are changing the way hydrocarbons are produced by optimizing production from downhole, supporting extend the life of artificial lift systems and providing information used to update reservoir and production models. A new technology that combines sensors with wireless telemetry provide the operators with new versatility and capability to place sensors in areas of the wellbore that were prohibitive due to technical difficulties and/or economic justification. The ability to communicate in and out of the wellbore using wireless systems can increase the reliability of the production system and decrease the amount of time required for the installation of the completion hardware in the wellbore. The elimination of cables, clamps, external pressure and temperature sensors, as well as splices on the cable that can fail inside the wellbore provides a significant advantage when attempting to place sensors in wellbores to monitor production or to optimize the pumps used in Artificial Lift applications.

Automation electronics manufacturers have been focusing a great deal of their development efforts on the plunger lift control application during recent years. The objective has been to automate this process

Real time analysis and visualization of the performance of a rod pumped well are achieved using multiple small and
compact wireless sensors that simultaneously transmit acquired data to a digital laptop manager that integrates the
measurements, displays performance graphs and provides advanced tools for analysis and troubleshooting of the
pumping system.
Battery powered wireless sensors for fluid level, pressure and dynamometer data acquisition are easily deployed and
quickly installed on the well. The laptop manager automatically recognizes and commissions the sensors. The user
sets up and controls the acquisition of data which may include multiple sensors that synchronously monitor variables
such as tubing and casing pressures, fluid level and polished rod acceleration/position and load as a function of time.
Elimination of cables and connectors improves the reliability of the hardware and data while speeding up the set-uptear-
down process. The user interface presents a smart instrument rather than a complex application.
Among the many innovations provided by these well performance analysis tools stand out the real time visualization
of the operation and fluid distribution in the down-hole pump, the simultaneous display of quantitative surface and
pump dynamometer graphs in conjunction with fluid level and wellbore pressures. Acquired data, wellbore
description and pumping system characteristics are saved as a historical data base creating a continuum of the well's
information and performance for direct comparison and detailed analysis.
The paper describes the hardware and user interface, the procedures for installation and acquisition and several
examples of field data and well performance analyses for a variety of rod pumping installations.

Development of the REDA PC progressing cavity electric submersible pumping system began in 1991. The primary driving force behind this product development was the problem of accelerated wear of sucker rods and production tubing in deviated and horizontal wells when using surface driven progressing cavity pump systems. Many producers were replacing sucker rod and production tubing strings multiple times per year. This was severely affecting the economic viability of the oil wells. Since May 1994, REDA PC units have been installed in over 60 oilwells. The main cause of pulling the pumping system has been pump life. The harsh downhole conditions reduce the pump"s, ability to produce fluid while the REDA PC drive system is normally unaffected. As a result, a customer requested that a system be designed that would allow the pump to be pulled and replaced while leaving the bottom drive system undisturbed. This paper will describe the tubing deployed REDA PC system and explain the wireline retrievable configuration, the in-well testing to date, and the future developments for the system.

The "Wolfberry" play is named after the two main productive formations, the low-permeability Wolfcamp and Spraberry, and is a very large part of the everyday business in the Permian Basin. Activity in the Wolfberry has recently increased, spurred by the current relatively strong oil prices. However, the economic foundation of these producing wells is their stimulation and the management of completion costs. All of these wells require multistage fracture treatments to achieve economic production and therefore significant effort has been given to continuous improvement in efficiently completing and fracturing Wolfberry wells. To illustrate the evolution of the optimization process, a retrospective of the changes implemented in fracturing Wolfberry wells over the past 10 years in several counties in the Permian Basin is presented. This paper addresses in particular, choices involved in optimizing stimulation stages (including perforation schemes), treatment fluids and proppants, to maximize net present value contribution of the hydraulic fracturing treatments.

One of the most common problems encountered in designing a stimulation treatment is a low working pressure rating of surface equipment. Quite often, tubular goods are capable of much higher working pressures than the wellhead equipment, and the primary limit of pressure and injection rate is above ground. Breakdown and "Ball Out" treatments are often restricted by low working pressure ratings when the maximum allowable pressure at the pump is less than the pressure required to inject fluid into new or fluid-damaged perforations. Even though high pressures may be required for only a few minutes, it is vital to successful completion of a well that each perforation or zone be opened. Pressure limitations can be especially critical since the fracture area developed and proppant transport are direct functions of injection rate. When the pressure limiting component of a well system is above ground it can usually be "upgraded" safely and reliably by one of these methods: 1. Isolating the wellhead from treating pressure 2. Substitution of a "Treating Tree" for the production Christmas tree 3. Special landing joints or "Top Out Joints" for working through blow out preventers or wellhead assemblies where conventional trees have not been installed. Each of these methods has its strong and weak points and warrants detailed examination.

Almost everyone connected with the oil and gas business will, at one time or another, be faced with rules and regulations governing oil and gas operations. The purpose of this paper is to present a generalized concept of some of the laws adopted by the various regulatory agencies in Texas and New Mexico. To completely encompass all rules and regulations in effect in the space and time allotted would be impossible. But, by supplementing the information contained in this paper with the reader's own knowledge and that available from other sources, one may gain a broader perspective of this particular phase of the oil and gas industry as well as a more complete understanding of the workings of the regulatory bodies.

Continuous coil tubing has become a viable alternative to the conventional workover method of injection well cleanout. With the increase in the wellhead price of oil, a greater emphasis is placed on the efficiency of in-place waterfloods. When an injection well within a flood becomes plugged, the method by which the well is monitored should indicate if there is a problem. Based on that indication and all available relevant data, a decision can be made as to the kind of problem which has developed and likely methods of correcting that problem. The use of coil tubing in many cleanout procedures is a cost- and time saving method. The circulation method is accomplished without the need of moving or disconnecting any part of the injection string. The wells do not have to be backflowed and stimulation jobs can be done with minimum exposure of the injection string to the corrosive effects of acid. A treatment technique can be designed to correct or counteract problems within the injection profile on a point-to-point basis.

Plunger Assisted Gas Lift (PAGL) in the Permian Basin Over the last few years Gas Lift has become a popular artificial lift choice for producing unconventional wells in the Permian Basin. Gas Lift is a good choice for producing wells with high bottom-hole pressures (BHP) and high gas liquid ratios (GLR). Gas Lift is also a good choice for wells that produce solids or have deviated wellbores. Gas Lift however like all artificial lift choices has an optimum range which typically tends to be above five hundred barrels per day. When Gas Lift gets below five hundred barrels per day inefficiencies begin to surface with regards to the amount of fluid produced relative to the amount of gas injected. These inefficiencies can be addressed by running a hybrid system of gas lift and plunger lift to help maximize fluid production and minimize injection gas with the use of an interfacing tool known as a plunger that free cycles up and down the tubing and keeps gas from breaking thru fluid while flowing to surface. The system known as Plunger Assisted Gas Lift (PAGL) is becoming more popular and some operators have gone almost exclusively to this choice as Gas Lift wells begin to mature. This paper will highlight operators in the Permian Basin who have successfully integrated these systems into their long term production plans and review before and after production numbers, costs and estimated annual savings and increases to net revenue. The mechanical aspects of the system will be reviewed as well as installation and best operating practices. Additionally a preview of producing the well intermittently as it continues to decline by another hybrid system known as Gas Assisted Plunger Lift (GAPL) will be reviewed. 
 

There are many potential failures in production wells which result from corrosive downhole environments, mechanical aspects of artificial lift or a combination thereof. Tubing failures constitute a costly failure mechanism in production wells. Tubing inspections can provide valuable insight on the condition of tubing as well as the distinction between causes of tubing degradation. This information is utilized to replace worn and pitted tubing joints, failure root cause analysis and implement solutions to mitigate future failures. Due to the high cost of a tubing failure, a high-quality tubing inspection is critical to identify potential failure mechanisms in a used tubing string. This paper serves to discuss the engineering and economic benefits of a tubing scanning program. The results of an in-plant inspection compared to an EMI wellhead inspection on two Anadarko wells in the Permian Basin exemplifies said benefits. This paper provides an in depth analysis of tubing inspection technology, the pros and cons of both wellhead and in-plant inspections and data utilization to reduce downhole failures.

High gas-liquid formation ratios appear as the fluid level decreases and as a result significant decreases in pumping efficiency are seen in the ESPs. This problem force frequent shutdowns in the pump because the gas is incapable of adequately cooling the motor and this forces the companies to maintain high fluid levels to avoid the formation of free gas at the pump intake, which increases the PIP and limits the production of fluid. A new and innovative downhole gas separator has been introduced in recent applications to treat gas slug’s problems. For these applications, a shrouded ESP with a double stage of gas separation connected to the bottom of the shroud as an intake was designed to break and separate gas slugs and avoid gas entrance into ESPs by forcing free gas to go around the shroud and produce through the casing. The gas separator uses an innovative design to break the gas slugs in the annular section between the casing and the tool, additional with the internal dual flow system the separation efficiency increases while it’s created a chamber lift filled with free gas liquid.  

With this new system, the fluid is now forced to pass through an additional gas separator which helps to separate gas and keeps lower PIP than usually promoting the fluid production in the wells.
 

When an insert rod pump gets stuck in tubing there will be a significant increase in well-servicing events. These events cost the consumer money and also places the worker's safety at risk. 

The Highway 80 area reviewed the number of stuck rod pumps in tubing conditions that had occurred from 2010 to mid-2017.  In total, there were 825 pumps that were unable to be pulled with rods, which resulted in tubing being pulled to retrieve the pump. To try and resolve this issue Pioneer used a rubber fin element below the discharge of their insert rod pumps. By doing so they saw a reduction in stuck pumps with the rubber element. Even though this method decreased the number of stuck pumps, about 10% of their pumps continued to get lodged in the tubing. 

In the third quarter of 2017, Harbison-Fischer implemented a design change to these wells. The Harbison-Fischer Brush Sand Shields were installed to all insert pumps going forward.

This paper will discuss the early results of approximately 18 months since the first Brush Sand Shields were installed. We will compare the pumps pulled that were stuck in tubing with and without the design change since the implementation. Our goal is to continue to review the trend to see if positive results are achieved. We will track the data and present it again in 2020. We have calculated that the additional cost of pulling tubing is more than 50% more than if the pump can be retrieved with the rods.
 

Abstract In 2019, we presented the early results of a design change on our insert sucker rod pumps in the Highway 80 field. The information presented previously was eighteen months of data after this change was made. We also included over seven years of data prior to the change. Today we will discuss the forty-eight months of data collected after the design change and more than 11 years reviewing sucker rod pumps stuck in tubing in this field. When an insert rod pump gets stuck in tubing, increases in well-servicing events drive costs and safety risks. The Highway 80 area team reviewed the number of pumps stuck in tubing from 2010 to July 31, 2021. There was a total of 1,159 insert rod pumps that could not be pulled with the rods to retrieve the pumps. Pioneer Natural Resources previously chose to use a rubber fin element below the discharge of their insert sucker rod pumps to prevent lodging from occurring. With this change, there was a reduction in pumps stuck in the tubing, but approximately 10% of their pumps continued to get stuck. In 2017, Harbison-Fischer installed their brush sand shield on all of Pioneer’s insert pumps in the Highway 80 field and continues to do so today. This paper will discuss the results of forty-eight months since the first brush sand shields were installed. We will compare the pumps that were stuck in the tubing with and without the design change since the implementation. 

Data from acoustic fluid level and surface pressure measurements were acquired by a standalone programmable monitoring system that uses internet and cellphone communication with the Cloud for remote monitoring of pressure transient well performance. The system named Remote Asset Monitoring or RAM is described in detail in this paper that presents results from tests that lasted several weeks, beginning with well shut-in, continuing until pressure transient stabilization and afterwards during pump down until normal steady state production operation. The progress of the buildup test was monitored remotely by downloading the acquired data and reviewing the pressure trend with additional measurements acquired manually as needed. After buildup stabilization the pumping system was activated and during pump-down the fluid level, dynamometer, pressure, and motor power measurements were acquired automatically based on a user defined schedule. The combined results of the analysis were used to estimate reservoir performance and well productivity. 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.