Workover Rig Research Articles

Study Evaluates Long-Term Corrosion Risk of Load-Bearing, High-Power ESP Cable

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 34898, “Long-Term Corrosion-Risk Evaluation of Load-Bearing, High-Power Electrical Submersible Pump Cable,” by Serko A. Sarian, SPE, Alkhorayef Petroleum, and Hattan Banjar, SPE, and Chidirim Ejim, SPE, Saudi Aramco, et al. The paper has not been peer reviewed. Copyright 2024 Offshore Technology Conference. _ In this study, a fit-for-purpose electrical submersible pump (ESP) load-bearing power cable was deployed inside the production tubing of a sour oil well for an extended period of service. Project economics required the power-cable metallurgy to survive long-term exposure reliably for up to 15% hydrogen sulfide (H2S) and high-salinity production fluids. Laboratory tests simulating varying sour well and extended galvanic corrosion conditions have been performed to determine the adequacy of the selected armor metallurgy in downhole corrosive environments. Introduction In recent years, various types of load-bearing power cable-deployed ESP (CDESP) systems have been introduced, eliminating the need to install or remove a conventional ESP along with the completion and reducing ESP changeover time by more than 80%. More recently, live-well CDESP systems have been developed and tested to eliminate the need for a well-kill operation. The most-critical and costly component of such a system is the load-bearing power cable. The cable has the dual purpose of conveyance and long-term powering-up of the ESP. In a conventional artificial lift operation, the ESP is conveyed using the production tubing with a non-load-bearing power cable strapped to the outside of the tubing. This operation requires a workover rig to remove and reinstall the entire completion and a killed-well operation that might permanently damage the reservoir. The main advantages of a CDESP system include operational efficiency gain and cost reduction, no reservoir skin damage, and production-loss minimization. However, a few challenges exist with the use of CDESP. These cables must have significantly different structures from commercial oil and gas power cables. These differences are detailed in the complete paper. Cable-Design Requirements CDESP system criteria include multiple-year continued service in adverse oilwell and reservoir conditions such as sour fluids, high gas/oil ratios (GOR) and temperatures, and abrasion caused by solids production. The following product acceptance requirements were set in advance: - Three redeployments or retrievals after the initial deployment - Single deployment continued runtime to meet or exceed the regional conventional ESP system runtime Based on regional statistics, a conventional ESP system single-deployment average run time is 2.5 years. The effective CDESP power-cable service life target then becomes 2.5 years × four total deployments = 10 years, which served as the basis for all cable-associated testing and reliability metrics.

Design and field-scale demonstration of the buoyant-kill process for restoring integrity of wells with sustained casing pressure

Sustained Casing Pressure (SCP) is the persistent casinghead pressure resulting from the well’s annular integrity loss and migration of gas above the leaking cement sheath. Downhole—intervention methods for SCP removal employ workover rigs to access and plug off the leaking annulus at depth from within the well. The inexpensive rig-less method of Buoyant Kill involves surface injection of immiscible heavy fluid at the casinghead into the well’s annulus to replace the annular fluid column above the gas-leaking cement and stop gas migration. Laboratory and pilot-size testing have shown feasibility of the method. Presented here, is a field-scale demonstration experiment conducted in a pressurized 2750-foot well with water displaced by an immiscible brominated organic fluid over 20-h long operation. Discussed is experimental design supported by fluid selection study, benchtop and pilot tests, and fluid transport model. Also analyzed is the process performance and operational problems. The results confirm feasibility of the Buoyant Kill technique for SCP removal. The overall change of the wellhead and downhole pressures follows the expected patterns indicating partial removal of the simulated SCP. The removal is incomplete due to pumping pressure pulses and wellhead pressure variations resulting in some emulsification of the two fluids and partial loss of the injection fluid into the overflow. The results show that wellhead pressure control and injection pump operation are critical for successful SCP removal using the Buoyant Kill technique.

Challenges and Practices for Recovering Stuck Coiled Tubing Pipe

Summary Stuck coiled tubing (CT) is a main operational risk leading to delays, deferred production, or even the loss of a well. Despite general commonalities, each CT recovery can face unique challenges, including managing high pressure, working under limited spatial or lifting constraints, establishing well control, or handling a cable inside the CT. This study consolidates learnings and proposes a general workflow for a basic stuck pipe scenario, rig up, recovery pressure control equipment (RPCE) and well control, CT free point evaluation, bottomhole assemblies (BHAs) and workflows for cutting and freeing the CT pipe downhole, and recovery of the CT at the surface. A consolidation of published case studies provides specific examples of the hardware, workflows, and operational considerations. In addition, the presentation of a recent case study extends the discussion to the challenges introduced by the presence of a cable in the stuck CT and its respective solution. The case study reviews the planning and execution of a CT recovery, including the use of decision trees to guide the decision-making process. It details fit-for-purpose hardware for safely anchoring the cable; packoffs for accessing, tensioning, and recovering it with slickline (SLK); an opening for deploying the wireline (WL) cutting BHA; and valves for pressure testing and well control. That workflow successfully freed 6,818 ft of stuck CT and allowed recovery of the pipe without a workover rig on location, eliminating 11 days of rig time during subsequent tubing pulling. This is the first such documented recovery case worldwide based on a thorough literature review.

Hybrid Gas-Lifting Method Optimizes High-GOR Production

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 209721, “Hybrid Artificial Lift-SRP/Gas Lift for Oil Production in High-GOR Environments,” by Kuldeep Chanchlani, SPE, Ranjit Gogoi, and Sukumar Awasthi, SPE, ONGC, et al. The paper has not been peer reviewed. _ The casing gas-pressure-operated rod-lift (CGPORL) system described in the complete paper consists of a sucker rod, pump, gas-lift valves, downhole gas anchor, and tubing string. The completion was invented to save workover rig cost, reduce production deferments, and increase production efficiency in high-gas/oil-ratio (GOR) environments in marginal fields. CGPORL System Description The hybrid-lift system includes gas-lift and rod-lift modes, allowing operators to switch between two modes of artificial lift without costly workovers (Fig. 1). The key factor is the ability to isolate or communicate between the tubing and the annulus without pulling the tubing string out of the hole. Gas lift requires that the annulus should isolate tubing in order to inject gas through valves installed inside pocket mandrels, whereas rod pumps need communication between the tubing and annulus for passage of liberated free gas. Mechanism The gas-lift valve opens once annulus pressure develops over the valve-closing pressure. Once free gas is released into the tubing and the injection valve is closed, the annulus becomes a closed system. The free gas released from the downhole gas anchor gradually pressurizes the annulus until the valve opens for the next cycle. This mechanism indicates an intermittent gas-lift process in a cycle. When the well ceases to flow because of rod-lift failure, the well When the well ceases to flow because of rod-lift failure, the well will continue to flow through the annulus by keeping open the annulus valve connected to the nonreturn valve. Because of the nondevelopment of annulus pressure in case of rod-lift the CGPORL system. failure, a mobile air compressor can be used for valve unloading until the rod pump can be serviced. As the solution gas is recombined with liquid above the pump-setting depth, the hydrostatic head is relatively decreased. If the gas-lift valve is placed at a shallower depth, the drilled well length contributing to the reduction of fluid density is short. If the pump is placed at a deeper depth, annulus pressure can be high, so the gas-lift valve can be placed in a low position. Optimization for the point-of-pump setting and gas-lift-valve setting depth is required. These effects are related directly to the frequency of injection and rate, which must be examined along with economic and safety factors.

A data-driven optimization model for the workover rig scheduling problem: Case study in an oil company

After completion, oil wells often require intervention services to increase productivity, correct oil flow losses, and solve mechanical failures. These interventions, known as workovers, are made using oil rigs, an expensive and scarce resource. The workover rig scheduling problem (WRSP) comprises deciding which wells demanding workovers will be attended to, which rigs will serve them, and when the operations must be performed, minimizing the rig fleet costs and the oil production loss associated with the workover delay. This study presents a data-driven optimization methodology for the WRSP using text mining and regression models to predict the duration of the workover activities and a mixed-integer linear programming model to obtain the solutions for the model. A sensitivity analysis is performed using simulation to measure the impact of the regression error in the solution.

Forecasting the technical efficiency of mobile workover rigs

Purpose. To propose a method of comparative evaluation of technical efficiency of mobile workover rig by the criterion of life cycle cost. Methodology. The proposed method is based on the determination of the specific discounted costs related to the technical condition of the machine, spent on a conventional unit of work performed. It combines economic and technical indicators that characterize the performance of the machine. This makes it possible to indirectly assess its technical efficiency. Procedures for obtaining and processing input information, analytical dependences for establishing the components of the mathematical model and its solution are shown. Findings. Using the proposed method, a comparison is performed of three conventional similar models of workover rigs, which are positioned as more reliable, and two which are less reliable and cheaper. Their indicators are formed as a weighted average based on the analysis of an array of statistical information. The obtained values were used to indirectly determine the specific discounted costs for the maintenance of rigs in working order for a period of time; the rigs are characterized by the indicator of technical efficiency. The comparison of these indicators for similar workover rigs is performed for such characteristic points as the moment of balancing of expenses, expenses for the forecasted period of operation, the periods of operation at which expenses are balanced. It is confirmed that usually the gain from the greater durability far exceeds the reduction of the economic effect of the rise in price of the machine. Originality. The proposed method for engineering forecasting of technical efficiency of technological machines using values of economic and technical indicators available to engineers of the petroleum industry. Practical value. This assessment is intended to objectively compare several analogue models and make a reasonable choice of a more efficient technological machine.

A Fuzzy Inference System for Detection of Positive Displacement Motor (PDM) Stalls during Coiled Tubing Operations

Positive Displacement Motors (PDM) are extensively used in the oilfield, either in drilling or in coiled tubing (CT) operations. They provide a higher rate of penetration and the possibility of drilling horizontal wells. For coiled tubing operations, PDMs can mill through obstructions and enable shut-in wells to work again. One of the major challenges while using these tools is the motor stalling, which can lead to serious damage to the PDM and lost time events in drilling and workover rigs. These events result in total losses of hundreds of thousands of dollars, and their avoidance mostly depends on trained and fully aware equipment operators. If a PDM starts to stall, the pumping needs to be halted immediately or the tool may fail. This paper describes the use of a Fuzzy Inference System (FIS) to detect the stalling events as they start to happen using the acquisition data from the coiled tubing unit, the output of the FIS could then trigger an alarm for the operator to take the proper action or remotely stop the pump. The FIS was implemented in Python and tested with real CT milling acquisition data. When tested using real data, the system analyzed 68,458 acquisition points and detected 94% of the stalling events across this data during its first seconds, whereas, during the real job, a CT operator could take longer to notice this event and take the proper action, or even take no action. If the FIS was applied on a real coiled tubing acquisition system, it could reduce PDMs over-pressurization due to stalling, leading to an increase on its useful life and decrease on premature failure. As of now there is no similar system in the market or published and this kind of operation is fully performed using human supervision only.

Surgical Coiled Tubing Stimulations: Step Changes in Effectiveness, Efficiency, and Characterization of Waterflooding Interventions

Summary An innovative coiled tubing (CT) real-time flow measurement tool was introduced in Ecuador to reformulate the stimulation workflow in water injectors, which comprised evaluation and treatment. This new technology enabled an integrated, single-run workflow instead—initial injectivity measurements, diagnostics, treatment, post-stimulation injectivity measurements, and final diagnostics. This novel, rigless approach reduced equipment footprint, operational time, and cost, and it improved production as compared with the conventional approach, despite accrued capital discipline constraints. Conventionally, operators rely on workover rigs and multiple product lines to diagnose, stimulate, and evaluate injector wells. Several challenges and inefficiencies were addressed by deploying the CT real-time flow measurement tool. Each intervention was designed to be completed with a single CT run and without the need for a workover rig, thus saving cost and time. Tailored diversion methods substituted the need for drillpipe to set mechanical packers. Prestimulation injection logging test (ILT) results obtained with that innovative tool, coupled with real-time control of depth and high-pressure jetting during execution, enabled effective placement of the stimulation treatment. Ultimately, post-treatment ILTs confirmed treatment effectiveness and final wellbore downhole conditions. Introduction of the CT real-time downhole flow measurement tool allowed operational objectives to be met in a single run, without additional interventions, with or without a workover rig on site. When workover rigs were present, this improved workflow saved an average of 15% operational time. In cases without a workover rig, 105 hours of rig time were saved (without considering rig mobilization time). Four case studies are presented. The first two cases demonstrate how acquisition of ILTs throughout the intervention enabled optimization of fluid placement and introduction of diverter methods. The third case covers a scenario where there was an initially low injectivity and highlights the challenges and lessons associated with recovering injectivity. The fourth case presents challenges unique to flowmeter measurements in heavy-oil environments. In each case, effectiveness of the optimized treatment was measured by two metrics: improvements in net injectivity and uniformity of injection profile, both of which drive the effectiveness of secondary recovery in connected producer wells. On average, wells intervened with this approach featured an improvement in injectivity of 301% (compared with 226% conventionally) and in their injection profile homogeneity by 13%. As a result, the productivity in connected wells improved by as much as 74% and an average of 39% (compared with 14% conventionally). This innovative workflow is a step change over conventional approaches to rejuvenate waterflooding. It combines the capabilities of delivering treatments via CT and the power of real-time downhole flow measurements to break the paradigm of multiline, multirun operations to remediate and stimulate injector wells. This yields logistically leaner operations, which are less costly, and it enables breakthroughs in secondary recovery through data-enriched interventions in times of budget pressure, not only in Ecuador, but also across the globe.

Concurrent 18. Presentation for: Wireline packer remediation using novel bismuth technology

Presented on Wednesday 18 May: Session 18 Prior to the execution of this project, there were limited options for repairing a failed production packer. Conventional oilfield practice would default to a well workover to replace the failed component. In an offshore environment, this approach not only carries significant capital cost, but also material risk and health, safety and environment exposure associated with the large operational footprint and time requirement of the operation. An innovative solution was developed to remediate the failed packer without a workover while simultaneously significantly reducing cost and risk. A new packer was formed by melting a bismuth alloy plug into the annulus using wireline equipment, eliminating the requirement for a workover rig. Bismuth alloy pellets were deposited onto the packer via precisely drilled holes in the tubing before being melted into an annular plug, forming a gas-tight metal-to-metal seal. As this was an industry first, prototype testing of the annular bismuth plug was undertaken to demonstrate concept feasibility. After a series of iterative testing a viable concept was achieved, and the prototype was taken forward to qualification. The annular plug was qualified to industry standard ISO 14310 V0 for the well’s operating conditions which included both pressure differential and axial loads. After the bismuth annular plug was qualified, the deployment method for the bismuth pellets was optimised to ensure they reached targeted location without compromising well integrity. After 2 years of design, the industry-first wireline intervention was successfully executed in 2021 and the well was returned to production. To access the presentation click the link on the right. To read the full paper click here

Wireline packer remediation using novel bismuth technology

Prior to the execution of this project, there were limited options for repairing a failed production packer. Conventional oilfield practice would default to a well workover to replace the failed component. In an offshore environment, this approach not only carries significant capital cost, but also material risk and health, safety and environment exposure associated with the large operational footprint and time requirement of the operation. An innovative solution was developed to remediate the failed packer without a workover while simultaneously significantly reducing cost and risk. A new packer was formed by melting a bismuth alloy plug into the annulus using wireline equipment, eliminating the requirement for a workover rig. Bismuth alloy pellets were deposited onto the packer via precisely drilled holes in the tubing before being melted into an annular plug, forming a gas-tight metal-to-metal seal. As this was an industry first, prototype testing of the annular bismuth plug was undertaken to demonstrate concept feasibility. After a series of iterative testing a viable concept was achieved, and the prototype was taken forward to qualification. The annular plug was qualified to industry standard ISO 14310 V0 for the well’s operating conditions which included both pressure differential and axial loads. After the bismuth annular plug was qualified, the deployment method for the bismuth pellets was optimised to ensure they reached targeted location without compromising well integrity. After 2 years of design, the industry-first wireline intervention was successfully executed in 2021 and the well was returned to production.

Lessons Learned in Horizontal Well Workovers and Sand Cleanouts, in Cerro Negro Field, Venezuela

Summary The Orinoco Oil Belt in Venezuela contains the largest known deposits of heavy oil in the world, and Cerro Negro is part of the fields in this area. However, the sand production is a major issue which affects the oil production in this field. There are some major issues that stand in the way of the proper cleanout of these wells. These problems include low reservoir pressure, geometry of the wells, and extremely high oil viscosity. Another major problem is the presence of big pieces of progressing cavity pumps (PCP) elastomers, some metallic parts from pressure and temperature sensors configuration, and other metallic parts from previous workover rig operations, encountered during cleanout operations. As a result of these difficulties, some of the past jobs performed in this field were unsuccessful. After these unssuccessful jobs, a campaign of recent multiple sand cleanout jobs was planned in the Cerro Negro field. Numerous difficulties arose during these jobs. These issues were largely due to the presence of big pieces of PCP elastomers and metallic parts. An additional issue was the low reservoir pressure. Due to the size of the casing/liner and the horizontal section, the annulus fluid velocity obtained was insufficient. Therefore, several techniques were applied to overcome these problems. One of these methods was to use reverse circulation for the sand cleanout in the 9-5/8-in. slanted casing section, while circulation was still possible to obtain a higher fluid velocity. Afterward, once the circulation was lost, a special stroking pump was used alongside a large string of tubing to store large amounts of sand and debris. This tool was also used to recover pieces of PCP elastomers and other metallic parts. This tool uses a piston pump to create a vacuum effect, and fluid circulation is not needed for the cleanout. Without this innovative stroking pump, it would have been almost impossible to recover these large pieces. This was the first time this innovative tool was used in these types of wells. When the open horizontal 7-in. production zone was reached, coiled tubing (CT) was used with the proper proportion of diesel and nitrogen to obtain enough fluid velocity and the proper equivalent density. In the end, when necessary, a smaller reliner was run depending on the information obtained during the analysis of the grain sizes. Some techniques were applied to run the reliner successfully in an old and worn out casing, where the geometry of the well and high doglegs caused difficulties. The challenges to complete the cleanout of the well with lost circulation problems included a large annulus area in the highly slanted and horizontal sections, the extremely high oil viscosity, and the presence of large pieces of PCP and metallic parts. These challenges were overcome by using different methods such as the special stroking pump, reverse circulation in the 9.625-in. section, and CT with the proper diesel and nitrogen proportions. Additionally, to keep sand production under control in the cleaned wells, a smaller reliner was run. Finally, these workover jobs were finalized to bring these wells back into production successfully. The oil production results of these operations are shown in this paper, and demonstrated that it is possible to retrieve the production in the sanded wells of the Orinoco Belt in a profitable way.

E&P Notes (February 2022)

E&P Notes (February 2022)

Finite element analysis and optimization of workover derrick based on ANSYS Workbench

Based on the actual workover operating conditions, this paper designs a workover operating machine for lifting and running tubing at the wellhead, and use SolidWorks to draw a three-dimensional model of the workover rig, through ANSYS Workbench, the main component of the workover rig is analyzed for the force under load. According to the results of static analysis and modal analysis, it is concluded that the main stress parts of the workover derrick are on the two uprights where the robot arm is installed, and the upper part of the workover derrick is most prone to resonance, after multi-objective optimization of the workover derrick, the deformation and the maximum stress of the workover derrick have been reduced by 9.5% and 9.8%, respectively. This research content provides a reference for the design of workover rigs in the future.

Innovation and instrumentation in CO2 monitoring wells for reservoir surveillance and advanced diagnostics

In 2015, CO2CRC Ltd embarked on an ambitious plan to field test innovative technologies to monitor a CO2 plume injected into a saline aquifer with a view to address many of the economic and environmental concerns frequently associated with commercial carbon capture and storage project’s long-term monitoring programs (Jenkins et al. 2017). It was called the Otway Stage 3 Project and it was focused on testing the technologies of seismic and downhole pressures applied in unique ways to monitor an injected plume of approximately 15000 tonnes as it developed and migrated in the subsurface. To achieve this goal, five new wells were drilled at CO2CRC’s Otway International Test Centre – one dedicated to injection (drilled in 2017) and the remaining four wells (drilled in 2019) were used for monitoring purposes. Each monitoring well and the gas injection well, were outfitted with fibre optic systems installed and cemented outside the casing (specifically for seismic monitoring) and with pressure gauges installed at the reservoir depth. The challenge of the installation was to install fibre optics outside of the casing, cement them in place securely and to perforate the wells without damaging the fragile TEF bundles. While the installation of the pressure gauges in the injection well was a conventional in-tubing gauge mandrel, the installation in the monitoring wells, which were to be used for water injection as well as pressure monitoring, used a less conventional deployment method, where the gauges were instead installed using a more economic and flexible approach by suspending the gauges from the wellhead via a hanger system. This not only ensured continuous offline monitoring of the downhole well pressures and temperatures, but also facilitated future well operations by simple wireline retrieval and deployment of the gauge, forgoing the need for a workover rig. The various systems were commissioned over the period of March–June 2020 and were in full operation in the second half of 2020 – all successfully operating and acquiring baseline data remotely as designed. The Stage 3 Project commenced gas injection operations in December 2020 and data acquisition using the innovative systems have commenced successfully.

Evaluasi Rigless Plug & Abandonment: Sebuah Studi Kasus

Oil was explored and found by Royal Dutch (Shell Group) geologist in early 1900. And since Indonesia’s independence, development in oil and gas projects was able to put Indonesia as one of major oil exporter country with daily production above 1 Million barrel per day in 1970 – 1990. With time as fields become mature, some of the fields have come to the end of its life cycle, where mostly 70% of Indonesia total old oil wells will have no economic value and has to be permanently Plug and Abandonment (P&A) as ruled by the government. It’s part of decommissioning an entire field with environmental preservation which called Abandonment and Site Restoration (ASR). As P&A will impact operating company investment as outlined in Ministry of Energy and Mineral Resources (ESDM) No. 15, 2008, efficient P&A operation should be evaluated to ensure proper planning and executions. The subject of evaluation is X well located onshore at Y Field, Java, Indonesia. P&A operation with multiple cements plugs as barriers to ensure no fluids migrations from one formation to others, or to surface. Evaluation between workover rig and rigless P&A operation with coiled tubing unit (CTU) and electric line (E-line) will be presented in this paper to value the expenditures and achieving the result as standardize by the government with accordance of operating company standard. Results show that rigless operation is the preferable solution, which lead to cost effective operation. Rigless operation saves 25% of P&A operations even tough with longer operation days.

A hybrid multi-objective genetic algorithm for scheduling heterogeneous workover rigs on onshore oil fields

Onshore oil fields are composed of a set of geographically distributed wells that, after some time of operation, might present some malfunction and have their production interrupted. When the oil production of some wells is interrupted, specially-equipped vehicles, also called workover rigs, are deployed to service the wells and guarantee that their activity is restored. Given the limited number of workover rigs and the large number of wells around the oil field, the workover rig problem consists of finding the best scheduling for the workover rigs, so the total production loss of wells is minimized. The scheduling considers some factors such as the production loss rate of each well, the service level required and the planning time horizon in which the schedule must be executed. This research presents a hybrid genetic algorithm to solve the multi-objective workover rig problem with a heterogeneous fleet and a finite time horizon. The hybrid genetic algorithm incorporates a variable neighborhood descent heuristic as a local search procedure to increase the convergence speed of the set of solutions. Both objectives of minimization of the production loss and fleet cost associated with the rent of workover rigs are taken into consideration. The fleet is held variable, so a workover rig depot is included at a strategic position on the oil field to guarantee that new workover rigs, besides the already existent ones on the oil field, might be included in the scheduling when required. The genetic algorithm was tested on a set of practical-sized instances up to 200 wells, 10 workover rigs and 300 as time horizon. Results show a high conflict between the objectives of minimizing the production loss and fleet cost for the workover rig problem, besides important aspects of the solutions obtained by the proposed algorithm.

Coiled Tubing Gas Lift Revives Dead Wells in South Pakistan

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper IPTC 19930, “Coiled Tubing Gas Lift: An Innovative Solution for Reviving Dead Wells in Southern Pakistan,” by Aizaz Khalid, Nestor Molero, SPE, and Ghassan Hassan, et al., Schlumberger, prepared for the 2020 International Petroleum Technology Conference, Dhahran, Saudi Arabia, 13-15 January. The paper has not been peer reviewed. Copyright 2019 International Petroleum Technology Conference. Reproduced by permission. This paper describes a coiled tubing gas lift (CTGL) technique successfully used to restart production from two pilot wells in a mature field in Pakistan that had been shut in since 2015. The project yielded production gains that resulted in a short payback period and verified that the technique represents an effective and economical solution to restart production in mature fields where conventional artificial-lift methods challenge well economics. The pilot results have encouraged the operator to further implement CTGL in Pakistan. According to the authors, suitable candidate selection, including data accuracy for nodal analysis and production forecast, and proper planning played fundamental roles in the project’s success. Introduction Exploration and production companies in Pakistan struggle with multiple challenges including pressure from regulatory bodies to increase oil and gas production to meet requirements of an energy-starved country in a period of historically low oil prices. With little new significant discovery, operators are challenged to produce economically from mature and declining fields. Several fields in south Pakistan have been forced to shut down because of uneconomical production rates. Most of the wells in these mature fields do not flow naturally because reservoir pressure is insufficient to overcome the hydrostatic column. Existing techniques have their own challenges, including very high associated costs. Realizing these challenges, the government of Pakistan recently prioritized developing mature fields and optimizing production in declining fields. Artificial-Lift-System Selection A detailed screening of candidate wells was carried out to identify innovative artificial-lift solutions. The deployment of gas-lift (GL) valves using coiled tubing (CT) soon emerged as the best option, offering the highest return in a cost-benefit analysis. CTGL is a rigless solution that enables setting GL valves at the required depth during any stage of a well’s life. CTGL strings can be installed without making permanent changes to already-existing wellbore tubulars, and make it easy to install in wells with either monobore or through-tubing completions. The technique allows gas to be injected through CT with production through the CT-to-tubing annulus. The system also is retrievable and replaceable when needed. Gas-lift mandrels (GLMs) and valves are added to the CT in a similar fashion to any traditional GL completion. A work-over rig is not required, and installation of the CT string also provides the opportunity to modify well cross-sectional flow areas, thus improving well hydraulics and production flow. Two flow configurations are possible: (a) tubing flow (i.e., production flow up the insert tubing string, gas injection down the newly created annulus) or (b) annular flow (i.e., gas injection down the insert string, production flow up the newly created annulus between parent tubing and the CT insert string).

SPE Strong: Strengthening Our Core: The Influential Yet Delicate Balance of Mentoring

President's column “The delicate balance of mentoring someone is not creating them in your own image, but giving them the opportunity to create themselves.”—Steven Spielberg One of my focus areas as SPE President is strengthening the feedstock of incoming talent into our industry. In my January column, I talked about industrywide initiatives under way to attract and retain this talent. This month, I want to engage with our members on the importance of effectively mentoring these bright, young minds. While I reflected upon setting my goals for the new year, I began to think about all of the important people in my career who not only helped me set high goals, but also provided support and guidance in achieving those goals. Some people were assigned to be my mentor, while others did it informally by providing advice during opportune moments. Truthfully, it does not matter how they became my mentor. The key point is that they were. Coaching a young professional in a technical position is critical to their success, but developing a person to have the interpersonal skills to navigate this industry is equally important. For 2020, my goals include being both a mentor and mentee. While I believe I have much to contribute to our younger members, I also have much to learn. I want to encourage more of our members to set goals around mentoring and want to make this the month where we take time to recognize and thank those who have had a positive impact on us as our mentors. Thank you, Don Patterson (retired Chevron), for mentoring me through my years of supervising workover rigs in northern Alberta. You were tasked with mentoring all the young engineers who were supervising rigs in northern Alberta, and phoning in our morning reports to you was often the most anxious part of our day. After looking back, your critiques were the necessary constructive feedback we needed. Fred Brownlee (retired Chevron) and John Patterson (retired ConocoPhillips) were two of my most influential mentors, both in helping me grow my technical skills and for connecting me with industry peers. Mike Mooney (retired ConocoPhillips) taught me how to be a great manager, how to conduct employee performance assessments properly, and how to set my focus on value-adding goals. Karen Draper (retired S&N Pump) and Carol Magney Grande (Magney Grande) provided mentorship on how to succeed in this industry as a working mother, and also gave me my first opportunity to serve on an SPE committee. Finally, I must thank Dr. Jeff Spath (SPE 2014 President). He became my mentor when I first served on the SPEI Board as a Technical Director and has continued to provide critical guidance and constructive feedback since. Without his help, I would not be writing this column as your 2020 SPE President.

All in the Family

All in the Family

Permian Pulse: Using Satellite Imagery Analytics To Track the World’s Busiest Oil Play

A trip on Highway 285 between Fort Stockton, Texas, and Carlsbad, New Mexico, is both fascinating and horrifying for the average commuter in the US desert Southwest. The 140-mile stretch of two-lane road can take hours to traverse on a given day as trucks hauling crude oil, sand, water, chemicals, and petroleum equipment overload the battered, sun-fried pavement. The mostly flat, dusty landscape is populated by drilling rigs, workover rigs, and gas flares as far as the eye can see. Even on the highway’s best day, most traffic laws are ignored as oilfield workers in pickup trucks race from site to site. The industrial chaos along the corridor serves as a snapshot of the now multiyear industry boom in the Delaware Basin and greater, 75,000-sq-mile Permian Basin. Keeping track of it all has become a massive challenge for operators, service firms, and midstream companies that make the basin move. They work in an environment that is changing daily, and they can’t afford to be caught by surprise when hydraulically fracturing a well, building infrastructure, delivering equipment to a remote area, or prospecting for new business. An emerging solution: an intelligent, continually updated view from above—or satellite imagery analytics. Companies such as Sourcewater, Planet, and West-wood Global Energy Group are stepping up to monitor the world’s busiest oil play by leveraging relatively inexpensive satellite technology and machine learning. Application of satellite imagery in the oil and gas industry is nothing new. It has been used by companies to monitor remote facilities. Market observers have used the technology to assess global oil supplies by tracking tanker traffic and storage levels. The World Bank has used it to estimate emissions from the flaring of natural gas and oil output by the Islamic State. The real breakthrough is in merging this capability with artificial intelligence and advanced analytics to aid planning for development, production, and logistics while providing competitor intelligence and market research. Development is still in the early stages as companies refine their models to produce the most reliable information possible, and products are just now being rolled out to clients. Finding Water in the Desert An early entrant in the satellite imagery analytics space, Sourcewater’s primary objective is to serve as an online data analytics platform and marketplace for oilfield water sourcing, recycling, and disposal. Founded in 2014 as part of MIT’s Energy Ventures program, Sourcewater “is really about providing oilfield water market intelligence” to its clients, which often are operators planning their completions and production work and logistics or midstream water companies determining where to add new capacity, explained Josh Adler, Sourcewater chief executive officer. Relatively new to the industry himself, Adler’s career path includes founding one of the Internet’s first match-making sites and serving as chief speechwriter to former US Treasury Secretary Paul O’Neill.