bluuebunny/crossref_metadata_2025 huggingface dataset:
Technology Development Framework: Moving From Qualitative to Quantitative Decision-Making
Authors: Clark Hamish P , Castellanos Diaz Orlando
Published: September 2022

Technology development in the energy sector typically suffers from an ad hoc approach to making decisions about the key questions of "What is the next de-risking step?" and "At what scale?". This lack of structure in decision making occurs despite the technology development process usually being within a stage gated protocol. This often leads to significant waste of time and resources and plenty of "surprises" about the extent of additional testing required.

The approach proposed in this manuscript is relatively simple to use, scalable, and transferable across industry sectors. Consistent application of the methodology has the potential to bring a quantitative rigor that can lead to more effective and efficient technology development and improve both intellectual and monetary capital allocation. Additionally, the framework provided facilitates a more structured and faster learning curve for people moving into technology development roles. Starting with a high-level understanding of the technology and business case, the methodology identifies possible commercial deployments and associates key technical and commercial risks that can be barriers to commercialization. Then, using a "Risk Burndown" approach based around an initial assessment of Probability of Success (POS), different Paths to Deployment (PTD) are developed. A Value of Information (VOI) approach is used to evaluate key metrics. This leads to a diverse set of de-risking options with associated trade-offs for informed decision making.

The methodology has been developed and deployed since 2017 across a portfolio of both incremental improvement and game-changing subsurface technologies at Suncor Energy, a large integrated Canadian energy company. Over 25 technologies have been progressed using elements of this workflow with 7 of the more complex and expensive projects employing the full quantitative VOI approach. These analyses have been used to inform decision making on over CAD 400 million of proposed de-risking activity spend.
Pseudo-Aquifer Index: A New Concept for Estimating Transient Water Influx using Kumar-Ramey Average Pressure Equation
Authors: Kumar A. , Banerjee D.
Published: September 2022

This paper presents a new concept of Pseudo-Aquifer Index and a major departure from classical methods to estimate transient water influx using Kumar-Ramey equation employing reservoir average pressure obtained from transient tests for a central well in a constant pressure reservoir. The new method overcomes the two limitations of the conventional methods of van Everdingen-Hurst (1949), Carter-Tracy (1960), Fetkovich (1971), and similar other studies. These methods require apriori knowledge of (1) pressure history at the reservoir-aquifer boundary (oil-water contact or OWC) with time, and (2) aquifer characterization in terms of rock and fluid properties, depth, and geometric configuration. Such data for aquifer and OWC pressure history carry a high degree of uncertainty at the beginning of a newly discovered complex offshore or onshore reservoir development.

Kumar-Ramey (1974) presented dimensionless water-influx (WeD) as a function of dimensionless average pressure and producing time which yields cumulative water-influx volumes as a fraction of cumulative reservoir withdrawal. Kumar (1977) also provided the dimensionless pressure at the reservoir aquifer boundary with time. Plots of dimensionless average pressure, dimensionless boundary pressures at the OWC, and cumulative water influx function (WeD) are presented as a function of producing times for the three cases of pseudo-aquifer-index of 0.25, 0.50, and 1.0. Some of this data is obtained from Kumar (1977) and is transformed into polynomial equations. Two examples show the applications, and compare transient water-influx results with those obtained from van Everdingen-Hurst method.

A log-log type curve of dimensionless average pressure and time is included for determination of reservoir properties when average pressure is known A considerable advantage of the new method is its simplicity, generality, ease in use, and implementation in reservoir engineering software and simulation when compared to conventional methods. This study is also the first to provide a systemic characterization of transient boundary (OWC) pressures in closed and partial water drive reservoirs.
A Deep Learning Optimization Framework for Geothermal Energy Production Based on Carbon Dioxide
Authors: Katterbauer Klemens , Qasim Abdulaziz , Al Shehri Abdallah , Al Sofi Abdulkareem
Published: September 2022

CO2 plume geothermal technology (CPG) has been developed in recent years by several companies. The technology aims to utilize CO2 stored in saline aquifers to produce geothermal energy. CPG is different from conventional geothermal concepts. Here, the feedstock utilizes CO2 as a carrier fluid through which heat is extracted from the subsurface reservoir. Furthermore, the system does not necessarily rely on shallow natural hydrothermal locations but can utilize a conventional sedimentary basis. At last, CPG can still harvest energy in low-temperature environments that are currently not suitable for conventional geothermal extraction.

We present a new deep learning optimization framework for the maximization of power generation from a CPG system. The framework utilizes an adapted N-BEATS approach. The approach is based on a stack of ensembled feedforward networks that are also stacked by interconnecting backcast and forecast links. The advantages of the framework are its flexibility with respect to different input parameters and various forecastable time series. This is particularly important for CPG to easily capture variations in the temporal dynamics and temperature responses across the various CO2 injection and production wells.

We evaluated the framework on a simulated CO2 storage reservoir based in the Taranaki basin in New Zealand. The Taranaki basin has been well studied for CO2 storage, given the presence of a large saline aquifer that may be well suitable for both CO2 storage and CPG energy production. We simulated 3.5 years of CO2 injection and production for geothermal energy production as input to the N-BEATS framework. The training performance of the network was strong, and the model's performance was then evaluated on subsequent two years of energy production. The deep learning framework is then integrated into a global optimization framework to optimize energy production while adapting CO2 injection.

The new deep learning N-BEATS optimization framework for CPG power generation represents an innovative way to enhance energy generation from CO2 storage reservoirs providing a sustainable way to minimize carbon footprint while delivering energy.
A Subsea Multilateral Oil Producer, Completed with AICD Sand Screens and Selective Inflow Valves is Evaluated by Combined Acoustic and PL Tools, Identifying the Sand Producing Branch and a Tubing Leak in a Single Operation
Authors: Troup Duncan , Griffin Tim , Pham Minh , Primarolo Andrew , Brighton James
Published: September 2022

Subsea completions offer a number of advantages, but intervention operations can be complex and expensive. A horizontally completed multilateral well exhibited unexpected sand production and a tubing leak leading to the well being shut in. This paper discusses the novel tools and techniques deployed to localise the tubing leak, identify the bore responsible for sand production and to provide relative sand quantification at differing flowrates

The evaluation methodology was essentially the same as a comprehensive production logging intervention, with the addition of a novel acoustic tool to quantify sand impacts. Data was recorded with the tools stationary while the well was flowed in a variety of different states by means of hydraulically actuated inflow control valves. This enabled well behaviour during transition from one state to another to be monitored in real-time and recorded, giving unprecedented insight into sand production dynamics, as well as sustained production from stabilised flowrates. Logging at different flowrates at different depths allowed quantification of minimum sand transport flowrates.

With the well shut-in, a leak detection survey was conducted while running in hole and a faulty GLV identified. With the well flowing comingled from both mainbore and lateral 2, data indicated a mixture of oil and water being produced, along with significant quantities of sand. Choking back both bores to 50% resulted in continued water and sand production. When the ICV was cycled to close lateral 2, water cut and sand production both increased with slug flow evident indicating the mainbore was producing sand associated with water production. Lateral 2 was then reopened and the mainbore closed. Sand production declined to zero and the water cut dropped, showing that lateral 2 was not producing either sand or meaningful amounts of water. The time-based data was recorded at depths, one in 3-1/2" tubing above the ICV and the other in 5-1/2" tubing higher up. For a given flow rate, it was possible to compare relative sand rates at the 2 points and infer the fluid velocities needed for sand transport to occur. The data identified the source of the sanding, the source of the water and the minimum flow needed to prevent sand settling in the well.

Robust and reliable detection of the presence of sand in 3-phase production flow is a powerful tool in itself to allow diagnosis of failures of sand control, in this case the positive identification of the bore responsible for sand production. The addition of a quantifiable fourth phase to traditional production logging elevates the understanding of downhole sand production by enabling the correlation of sand rate with variable parameters such as holdup and local fluid velocities.
Universal Drilling Language For Improved Safety and Efficiency in Rig Operations
Authors: Vincent Taylor , Teodoriu Catalin
Published: September 2022

What and how we communicate on the rigand around field operations needs some serious improvement. While there is already adrilling "vocabulary," it is inconsistent and informal. Without standardization, the current language is only moderately effective and existson a continuum somewhere between absent to incomplete. Other high-risk industries have benefited from implementing an architecture to their language,and this paper argues the energy sector would, too. The proposed Universal Drilling Language is based on the need to communicate commands, requests, affirmations, and more with precision and accuracy. Concise language considers what is necessary, excludes the extraneous, and transmits it clearly – leaving no room for misinterpretation. Creating an architecture to rig communications is essential for the next generation of engineers and operators to work safer and more efficiently.

The process for streamlining and arriving at an improved language architecture is iterative and can be accomplished by fusing human factors principles into simulation-based training. The "Driller’s Roadmap" (DRM) language experiment described herein allows pairs of traineesto use anindustry-standard drilling simulator totest and improve their communication skills. The pairs attempt rudimentary drilling tasks in three distinct phases of varying communication styles, and task performance is compared across scenarios. The communication phases tested include using "natural" intuitive words and phrases, scripted "imperfect" phrases, and scripted "perfect" phrases. Results show that exposing trainees of different backgrounds and experience levels to this simulation-based communication training can simultaneously improve their human factors skills and task performance. Furthermore, the DRMleverages drilling simulator technology tocreatea"human-in-the-loop" training methodology for the petroleumindustry. This research and itsresulting language will shorten the industry’s learning curve for future verbal-computer interactions and machine-based task interpretations. More importantly, the standardization of a drilling language can improve safety and efficiency for all future rig operations worldwide.
Investigation of Matrix Damage and Remediation Methods of Preformed Particle Gel Conformance Control Treatments in Carbonate Reservoirs
Authors: A. Almakimi Abdulaziz , Liu Junchen , Bai Baojun , A. Hussein Ibnelwaleed A
Published: September 2022

Preformed Particle Gels (PPGs) have been widely applied to control excessive water production in mature oil fields with fractures or fracture-like features, especially in sandstones, but with limited attention to carbonates. However, a vital concern arises regarding the potential damage of PPGs on the adjacent matrix that might promote negative results. This paper comprehensively evaluates PPGs’ potential damage to the carbonate matrix and seeks design optimization solutions. Filtration tests were applied to compare PPGs’ penetration into matrix under different sets of conditions. The filtration regimes were defined by filtration curves and the gel damage on matrix was determined by permeability measurement results. Experiments were conducted to investigate the efficiency of an oxidizer as a remediation method to remove the damage. The qualitative description of gel particles’ invasion and plugging behavior in the carbonate matrix was presented based on the analysis of filtration test results and permeability measurements.

Results show that the swollen gel filtration curves can be divided into three regions: prior-filter-cake, filter-cake-building, and stable stages according to the gel particles’ response to the injection pressure and effluent flow rates. PPGs can form cakes on the rock surface to prevent particles’ further penetration into carbonate matrix, and the penetration was only limited to less than a few millimeters. The smallest gel particles (50–70 US mesh size) were more likely to form external and internal filter cakes at higher pressure values (700 psi) and result in more damage to the matrix. To restore the matrix permeability after filtration tests, oxidizer soaking was proved to be a reliable solution. In all, the results indicated that unintentional matrix permeability damage induced by gel injection is generally unavoidable, but conditionally treatable.
Evaluation of Various Designs for Scale Inhibition Squeeze Treatments in Carbonate Reservoirs
Authors: Alissa Faisal , Altowairqi Rashed , Alhamed Khalid , Alsubaie Abdulaziz
Published: September 2022

Scale is considered as one of the major concerns in the oilfield industry. Usually, scale formation causes several issues such as: reduced production, formation damage, jeopardizing well integrity, and causing damage to assets such as artificial lift equipment. Therefore, a scale inhibition operation has to be conducted to sustain oil and gas production by assuring the flowing conditions of the reservoir and production assets. Scale inhibition in oilfield industry is carried out in one of four ways: 1- squeezing the inhibitor inside the formation, 2- continuously injecting the inhibitor through a capillary tubing, 3- apply an encapsulated inhibitor in the rat hole, 4- applying batch treatments. In this study, we are evaluating various treatment designs for the scale inhibition through the squeezing technique in terms of efficiency and lifetime. The efficiency of scale inhibition squeeze treatments is bound to a certain lifetime which depends on the interaction between the inhibitor and the reservoir rock. The inhibitor interacts with the rock in an adsorption fashion, then it desorbs to maintain a certain concentration in the aqueous portion of the produced fluids; thus, inhibiting scale deposition. When squeezing the scale inhibitor deep inside the reservoir, the inhibitor has a greater surface area to adsorb onto; therefore, less of it will be retained when flowing the well after the operation. The drawback of the squeeze technique is the duration, and the inhibitor loss right after the operation, the greater the inhibitor production the shorter the treatment lifetime. Squeezing the treatment deep inside the formation has reduced the inhibitor concentration; thus, increased the treatment estimated lifetime by almost 5 folds.
Pressure Transient Analysis of Fractured Horizontal Wells in Multiple-Well Pads With Complex Fractures Using a New Numerical Model
Authors: Chen Zhiming , Zhou Biao , Liao Xinwei , Wang Bin
Published: September 2022

The technology of multi-stage, multi-well pad fracturing is an effective way to increase the stimulated volume and recoverable reserves in shale reservoirs. During the fracturing treatments, there are common phenomena of well interferences from the multi-well pad. However, there still lacks an understanding on the transient behaviors of well interferences, which is harm for applications of well testing to analyze the parent-child interactions and to evaluate the fracture parameters quantificationally. To narrow this gap, pressure transient behaviors of fractured horizontal wells with secondary fractures and well interferences are studied by a numerical pad-well model, based on a discrete fracture model (DFM) and unstructured PEBI grid system.

First, the pressure transient solutions of fractured horizontal wells with secondary fractures and well interferences have been demonstrated by model verifications. The results show that the flow regime of interference effects caused by parent-child interactions are more obvious, with a larger child-well production, a smaller well spacing, and a larger hydraulic-fracture angle. The well interferences are also stronger when the child well has more secondary fractures, longer secondary fractures, and higher fracture conductivity, as the pressure drop caused by child well will propagate more quickly. Once the complex fracture networks have developed within the multi-well pad, the interactions between parent and child well will be weaker with the increase in area and conductivity of fracture networks. By comparison, the pressure transient behaviors of Parent well are remarkably affected by Child-well production rate, well spacing as well as connectivity degree. However, the angle, length, number, and conductivity of secondary fracture have weaker impacts on the pressure transient behaviors of Parent well. This work provides a meaningful way to understand the pressure transient behaviors and to evaluate the fracture parameters of multi-stage, multi-well pads.
Reformatting Petroleum Industry Communications for the Educational System and the Public
Authors: Ershaghi Iraj , Paul Donald
Published: September 2022

The Energy Transition is creating a new operational and strategic framework for the oil and gas industry. One specific dimension of this new framework is the management of "reputational risk" and "the social license to operate." Despite the clear and demonstrable contributions of the petroleum industry to our modern industrial society, the reputation of the industry in the United States is often seen as generally negative, and improving it remains a challenge. This poor characterization is negatively affecting the flow of new investment capital and recruiting of young talents to the industry. The power of negative publicity can also unnecessarily limit the development of needed oil and gas resources and infrastructures, with long-term economic consequences for the economic health and standard of living of the society. In this paper, we propose that the new societal expectations developing as part of the Energy Transition will require a "reformatting" of the industry's communication processes for both the educational system and the public at large to correctly position the industry as a positive and vital contributor.
A Review of the Digital Twin Technology Application in Energy Industry for Performance Improvement
Authors: Ahmad Shatiry M Sahir , Harun Firdaus , Azman M Muaz , M Amin Ahmad Helmi , Husni Zul Hazran , Abu Akbal
Published: September 2022

The paper investigated the use of digital twin (DT) technologies in the energy industry. It analyzed the available digital twin technology used in the energy industry using the SWOT method. The DT serves as the real-time presentation of the actual process or physical object with the Internet of Things (IoT). Typically, fabrication work productivity depends on the process flow and the human behaviours that contribute to delay or non-productive time—digital technology to learn the overall process, human behaviour, and machinery uptime. Visual learning was established to monitor the operation activity as well as the construction work and to capture the general behaviours of the human such as welding, resting, taking a break or even non-productive work such as break outside break hour, smoking, wrong sequence of the working process and other external interruptions. This study will explore all the available DT technology in the market and its function and capabilities and then identify five (5) DT technology applications that can improve performance in the energy industry. After that, to determine and summarize the strength, weakness, opportunity, and threat of all five (5) applications of DT technologies already used in the energy industry using SWOT methodology. The SWOT analysis found that the benefit in terms of Strength and Opportunity is more significant than the threat and weakness of the Digital Twin technology. Then, it is clearly indicated that the DT technology is capable of utilising in many other areas of business in objective to understanding the overall system efficiency and capable of providing information for accurate and precise decision making for the company.
Machine and Process Automation are Improving Personnel Safety and Drilling Performance
Authors: Whatley Michael , Ayanambakkam Arima , Patterson Derek , Farrow Blakley , Feng Le , Hewitt Parker
Published: September 2022

The industries’ number one priority is ensuring everyone goes back home in the same condition they came to work. With that guiding principal in mind, how could a drilling contractor work to substantially reduce our crews health, safety, and environment (HSE) exposure? Engineer solutions that take them off the most dangerous place on a drilling rig. Traditional drilling processes require personnel to manually handle tubulars while making connections, building stands, or racking back pipe. This requires personnel to perform strenuous tasks in dangerous areas. These areas often require personnel to work near moving machinery. Manual operations often lead to high degrees of variability in performance based on rig crew experience and familiarity of the operations.

Development of a fully automated rig required overcoming many challenges to process tubulars from the ground to well center. New machines were designed to meet the automation requirements. The ground handling system was designed to clean, dope, and measure pipe. The robotic pipe handler was designed to handle retrieving tubulars from the ground handling system, deliver to well center and spin in the connection. The automated floor wrench is responsible for making up connections. The rack and pinion hoisting system was designed to handle the drill string with precision and eliminate the need to slip and cut drill line.

To achieve the desired automated tripping and drilling process automation, a rig operating system with sequencing functionality, tubular management, and zone management was required. The rig operating system integrates the different machines and manages the necessary protections at the machine layer. The sequencing layer is responsible for coordinating the process automation at the appropriate set points for rotary drilling, slide drilling, tripping, and casing connections.

The robotic rig has currently completed 9 wells and has continuously improved since the start of drilling in August. The drilling connection times have improved by 28% and the rig became the third fastest across the fleet. Additionally, the rig has improved its casing running performance by approximately 43% and is now within a few joints of other top performing rigs in the fleet. Fully automated control of these processes guarantees consistent and repeatable performance across the wells drilled. This is all being done without the need to have personnel handling tubulars in the mast or on the rig floor.

The success of this first of its kind robotic rig can be attributed to partnerships with the operator, the drilling operations team, the rig engineering team and the controls and automation team. The teams collaborate to identify areas for improvement to continuously drive better, safer, and faster drilling.
Degradable Thermoset Composite Frac Ball for Offshore Well Stimulation
Authors: Kovalchuk Anton , Garza Ramon , Stone Matthew , Sadana Anil
Published: September 2022

Degradable frac balls are used widely in unconventional stimulation operations for sleeve activation. The objective of this work was to develop a new degradable frac ball product for challenging offshore multistage fracturing systems where conventional degradable metal frac balls have challenges due to high hydrostatic pressure or lack of suitable degradation fluid. The scope of work included creating a new blend of material and accompanying test methods to meet application requirements. These requirements were that the degradable frac balls i) exhibit no degradation in the ball launcher during stimulation operations, ii) are able to degrade at high pressures (up to 15000 psi) in the presence of oil below the ball and iii) create by-products that do not plug or adversely affect the completion/production.

In this paper, we report the development and testing of thermoset polymer composite balls designed primarily for offshore well stimulation applications. This polymer consisted of a cyanate ester thermoset composite that exhibited excellent mechanical properties (compressive strength 37 ksi; tensile strength 14 ksi and tensile modulus 2 Msi).

Frac balls with sizes ranging from 1.30″ to 3.18″ were compression molded and pressure tested to ensure a pressure differential rating of 5,000 psi across a ball seat with approximately 0.16 % engagement at 150°F. This material was found to degrade in fresh water and various brines when exposed for two or more days at temperature>250°F, making it applicable to deep-water completions. The residual products of the degraded composite balls were tested for production screen plugging and demonstrated no risk of plugging to the test equipment.

These results demonstrate the feasibility of this new material to be used for deepwater hydraulic fracturing operations.
Modeling Heat Pump Technology for Economically Attractive Decarbonized Oil Production Systems
Authors: Keihany Julian , Baaren Sander
Published: September 2022

Many operators with large stakes in unconventional shale oil plays have published targets to drastically reduce emissions with some considering carbon emission tax for economic evaluations of future projects. This creates the need for finding electrically powered alternatives to replace equipment that currently consumes fuel gas, such as fired heaters. Production facility designs for unconventional shale must be simple, robust and require relatively low CAPEX and OPEX to be economically viable. This poses a challenge for electrically powered alternatives because fuel gas is freely available at production systems, whilst electricity comes at a cost. To address this challenge, novel fully electric production system designs have been developed based on heat pump technology. The practical and economic feasibility for these designs are evaluated and demonstrated so that these can be considered as realistic solutions for future projects.

The major reasons why crude oil must be heated at upstream production facilities are to break potential emulsions of oil and water and to stabilize the oil. Stabilizing the oil means that volatile components are removed from the crude, so that it can be transported and stored in tanks without emission and safety concerns. The novel production systems achieve this by pairing a single stage electrically driven heat pump with heat integration. The novel production system designs are analyzed using steady state and dynamic simulations employing industry accepted process simulation software. The steady state simulations generate metrics such as energy consumption, estimated emissions and hydrocarbon recovery which are used in conjunction with emission factors and other economic factors to compare the performance to standard production facilities. The dynamic simulations are used to demonstrate the feasibility for starting-up and controlling the facility for this novel technology application.

The simulation results demonstrate that the heat pump based designs consume around 70% less electrical power compared to direct electrical heating. Further benefits are that the temperatures can be controlled at various stages in the process to substantially increase the facility's oil recovery. This also results in leaner gas, which is particularly attractive for facilities that include gas compression and dehydration. The increased oil recovery results in substantially higher revenue which leads to an economically more attractive design compared to a traditional facility, even without taking carbon emission tax into consideration. These comparisons are provided for different types of facilities during different production scenarios during varying weather conditions.
Next Generation Acid System — Deep-Penetrating Non-Corrosive Fluid for High Temperature Sandstone Stimulation
Authors: Zakaria Ahmed , Hudson Harold
Published: September 2022

In high-temperature sandstone reservoirs especially at temperatures above 450°F, the rapid reaction of the acid treatment fluid and the secondary/tertiary reactions with the clays lead to formation damage. Moreover, at these high temperatures, the HCl/HF based acid systems are extremely corrosive to the wellbore tubers and downhole equipment's. This paper presents the next generation acid system that utilizes non-corrosive fluids to generate HF acid for high temperature sandstone stimulation.

The non-corrosive deep-penetrating acid is a neutral, non-reactive treatment fluid at the surface and only when it is injected in the formation, it generates HF at a controlled rate in situ under temperature and time. The in-situ generated HF at a controlled rate allows for deep penetration of the acid in the formation. A series of solubility testing in HPHT reactor was first conducted to understand the chemical reactions that generate the acid as a function of temperature, concentration of acid generating components, and time, and to identify the optimum composition that maximize the dissolving of quartz and minimize the potential precipitation from reaction with clay minerals. Coreflow testing was then conducted at 475°F using 1.5″ in diameter and 6″ in length Berea sandstone cores to evaluate the performance of the new acid system for sandstone stimulation.

Solubility testing showed that the new acid system has high dissolving power for calcite and silica and potential to minimize precipitations when reacted with clays. In Coreflow testing, the non-corrosive deep penetrating acid is effective to stimulate sandstone and provides remarkable permeability improvement by at least 60% at 475°F. Because of the in-situ controlled generation of HF, it penetrates deeper in the formation and minimizes the potential for precipitations.

The non-corrosive deep-penetrating fluid system provides the industry with an effective solution to deeply stimulate sandstone reservoirs unlocking the full potential especially at temperatures above 450°F, and a safe non-corrosive fluid for wellbore tubulars and equipment. Moreover, the new fluid technology would eliminate the need for acid tanks on site, reduce transportation difficulties, and eliminates HSE concerns and acid exposure to personnel in the field.
Gas Lift Optimization Study in Brownfields: A Review on Dual String Gas Lift Injection Allocation In Malaysian Offshore Fields
Authors: Suggust Alister Albert , Kueh Jing Zhi
Published: September 2022

Sarawak offshore wells are mostly completed with dual string completion and are heavily relying on gas lift as the primary artificial lift. Dual string gas lift is an economical way to selectively produce from multi-stacked reservoirs in Sarawak fields. However, it poses great challenges in terms of operations, troubleshooting, allocation and optimization as both strings share a common annulus. Dual string gas lift performance diagnosis need to be done from time to time to ensure the strings production are optimized at well level.

Gas injection rate is a critical input in predicting the well performance based on the gas lift performance curve. However, the gas lift injection rate for dual string is measured at well – not at string level. The gas lift injection rate into each string needs to be allocated correctly either through well modelling calibration approach, testing one string while shutting its neighbor or well tracer application. After allocating the gas lift injection rate into each string correctly, well modelling prediction run at done to mitigate multipointing issues, design optimum point of injection, establish optimum injection rate at well level and determine the optimum casing head pressure.

The operator has proposed for a workflow to correct the dual gas lift injection allocation based on well modelling calibration. The workflow was implemented and resulted in multiple optimizations in terms of gas lift valve change program, choke optimization and gas lift rate optimization. Apart from that, the paper will also share on the findings from the well tracer application in correcting the gas injection allocation.

This paper will focus on the production performance check on dual string gas lift performance at well level. The findings from the study are subsequently monetized as quick-gain opportunities while the operator is embarking into long term study on assessing the alternative artificial lift strategy suitable for a brownfield. The lessons learned will also be applicable to oil fields with similar situations to further improve the fields’ production.
Microfluidic Study of Polymer Permeability Reduction Mechanisms
Authors: Kenzhekhanov Shaken , Yin Xiaolong , Gussenov Iskander
Published: September 2022

Polymer solutions see broad applications in hydraulic fracturing, enhanced oil recovery, conformance control, and groundwater remediation. However, due to the high viscosity of polymer solutions, flows after polymer injection are often subjected to significant pressure build-up, the mechanism of which is not well studied, especially on the effect of distribution of fluids in the pores.

In this study, we used microfluidics micromodels to visualize the distribution of fluids in porous media. NOA81 micromodels with close-to-real-rock pore dimensions were fabricated and used for simulating flooding experiments. Relative permeability was measured at steady-state flow rates and injection pressures. Then, fluid distribution was analyzed using microscopy image analysis.

We observed that the distribution of fluids in a porous medium has a direct impact on the pressure drop. The relative permeability of water and oil after polymer flow was disproportionally low, which is consistent with core flooding experiments. The increase in the pressure drop due to polymer trapping can be correlated to occupancy, orientation and alignment of pore channels. A mathematical model was developed to describe the correlation between pore-scale fluid distributions and the end-point relative permeability; it can be used for understanding and enhancing oil/water flows during/after polymer injections.
Failure Pressure Prediction of Defective Pipeline Using Finite Element Method and Machine Learning Models
Authors: Liu Wei , Chen Zhangxin , Hu Yuan
Published: September 2022

Oil and gas pipeline failure and leakage can seriously damage people's lives and the ecosystem. The prediction of failure pressure for pipelines with damage is one of the most important and challenging tasks faced by industry, which affects the assessment of pipeline safety. Previous studies widely used industrial models or the finite element (FE) method to predict the failure pressure. However, the industrial models may give limited information, and the FE method has much heavy computation burden.

In this work, three machine learning models - artificial neural network (ANN), XGBoost (XGB) and CatBoost (CAT) are developed for forecasting the failure pressure of pipelines with defects. Firstly, the simulation results of the FE method are validated by real failure pressure and compared with the calculation results of industrial models (ASME-B31G and DNV). Then 180 pipeline samples including pipeline attributes and defect sizes collected from real in-line inspection data in a pipeline company and the corresponding FE simulation results of failure pressure of these 180 defective pipelines are used for the training and testing of the machine learning models.

The results show that the simulation accuracy of the FE method is higher than the calculation accuracy of the industrial models, and the FE simulation results are suitable to be the outputs of machine learning models. The three machine learning methods all provide satisfactory prediction accuracy in failure pressure. Specifically, CAT is the best machine learning method in this study for its lowest relative error (3.11% on average), mean absolute error (0.53), root mean square error (0.78) and highest coefficient of determination (R2) up to 98% in testing. Moreover, the machine learning models present better performance on average relative errors compared to the industrial models. CAT shows higher accuracy than the industrial models and FE simulation on minimum and average relative errors. Finally, the prediction result of CAT is used to discuss the effect of input features on failure pressure of pipelines, which demonstrates that the importance of features follows the order of pipeline thickness > pipeline outside diameter > defect depth > defect length > defect width.

Once the above machine learning methods are used in industry, more and more real data will be collected to train a model and make it more accurate. In this way, these methods will provide an efficient way to evaluate the safety of defective pipelines. In addition, the failure pressure of pipeline could be estimated to help operators figure out a pipeline condition and further prioritize the pipelines for maintenance.
Effect of Formation Compaction and Subsidence on Sliding Sleeve Performance
Authors: Getzlaf Nick , Whyte Rio , Vanee Mike , Mberia Stanley , Gillis Brock , Werries Michael
Published: September 2022

Formation compaction and subsidence forces due to reservoir drawdown have the potential to inhibit the function of sliding sleeves and similar completion systems. The sliding sleeves discussed have the ability to be opened and closed multiple times, allowing for flexible stimulation and production operations. Field data suggested a link between high sliding sleeve function forces and preceding zonal production. The objective was to minimize these effects to give the operator full functionality of the sliding sleeves over the life of the well. This paper will outline how this was achieved, and the results of comparative lab testing.

The overall approach was to (1) understand the magnitude and effects of the formation forces, (2) implement product improvements, and (3) validate results through lab testing the proposed solutions.

A case study was conducted for 4.5 in. 21.5 lb/ft & 5.5 in. 32.6-35.3 lb/ft casing and sliding sleeves installed in the Valhall field. Wells drilled in the Valhall field had previously suffered production casing collapse failures due to formation compaction and subsidence (Pattillo and Kristiansen 2002). Switching to the current heavy weight casing resolved the issue. The heavy weight casing collapse pressure ratings were used in the early analysis to determine maximum uniform collapse resistance and radial deformation of the sliding sleeve components. Thick-walled cylinder calculations were insufficient for predicting the effect of the non-uniform loading exhibited downhole, as well as predicting metal-to-metal contact within the sliding sleeves due to abrupt changes in geometry. FEA modelling was completed for predicting metal-to-metal contact due to a non-uniform load.

Sleeves with improved mechanical collapse resistance were designed and built. Lab testing was conducted by applying a mechanical radial force simulating the formation load to (1) the original sleeves, (2) the newly improved sleeves, and (3) host casing samples. Sliding sleeve performance was assessed through the resultant opening and closing forces. Test results verified the model for radial deformation due to formation forces, and the effect on sliding sleeve performance. The improved sleeves showed no change in performance with a range of applied radial load, whereas the original sleeves showed significant increases in function force.

Completion design improvements can enable novel methods of well stimulation and production in areas prone to formation compaction and subsidence forces. These forces can have major effects on the completion and production of a well but are rarely quantified and accounted for in sliding sleeves or similar completion systems designs. At the time of writing, the improved sliding sleeves have been successfully run in a field trial, though did not produce prior to functioning.
Stranger Things 4: Placement Simulators Accuracy For ECD and Pressure Predictions
Authors: Shine Joe , Heinold Thomas , Lawrence Don
Published: September 2022

Cement placement simulators are valuable tools predicting anticipated pressures and equivalent circulating densities (ECD) for a given application. The simulators guide users in maintaining wellbore stability for a range of operating conditions unique to the application while helping to achieve the isolation requirements. There are various functions in the simulators, based upon the inputs, which contribute to the pressure and ECD predictions. Most of the available literature shows consistency for the solving the various transport equations of fluid dynamics including pressure losses as a function of flow regime, wellbore geometry, and fluid rheological model. Therefore, a comparison study should demonstrate consistency to avoid uncertainties in a given simulators prediction accuracy. The manuscript investigates the prediction differences in four available simulators that depending on the type of variability observed, could affect a well's integrity.
Relative Permeability Determination of Supercritical CO2 and Equilibrated Carbonated Water in Carbonated Rock of Brazilian Pre Salt Using Experimental and Simulation Methods
Authors: Vidal Vargas Janeth Alina , Borges Carvalho Talisson , Caicedo Garzon Alexander , Valladares de Almeida Rafael , Koroishi Erika Tomie
Published: September 2022

The relative permeability curve is the key parameter to determine the CO2 injection strategy in EOR and CCS processes as it can predict the CO2 flow over the reservoir life, and also through hysteresis it is possible to quantify the changes in the reservoir due to CO2 injection. In order to improve simulation fit and increase reliability in storage assurance the research work concerned experimental, analytical and simulation methods to study two-phase relative permeability of scCO2/equilibrate carbonated brine (ECB) system at reservoir conditions (5,000 psi and 70°C). Two techniques were used in order to perform the laboratory experimental tests for unsteady state using reservoir rock composite: X-ray computed tomography and mass balance. The absolute permeability was 106.7 (md) and the composite porosity measured by CT was 18.6%. At the end of drainage, the irreducible saturation (Swi) of ECB results by CT and mass balance were 39.5% and 36.2%, respectevely. The CO2 trapped was 11.09% from the CT data at the end of imbibition test. A simulation model was created using GEM/CMG and eight parameters of the model were optimized using the CMG Bayesian Engine method (CMOST/CMG simulator). The model fitting results are consistent with the experimental results (pressure differential, water production curve and saturation profiles). The history matching results for relative permeability curve provided Corey's exponents values for drainage test: Ng=4.76, Nw=2.30 and critical saturation of gas and water respectively, Sgcrit=0.1268 and Swcrit=0.3696. According to the results obtained from the simulation model, variation in permeability and porosity was observed due to dissolution and precipitation. The average values obtained for these parameters were 119.6 mD and 14.3%, respectively. The experimental work carried out to develop the relative permeability of scCO2/ECB under reservoir conditions and using sample of reservoir rock provided higher reliability due to the both measurements techniques appointed similar results. Also, the analytical approach performed in CMG GEM from experimental data promotes accuracy and confidence. Both experimental and analytical approaches provide reliable results to fill gaps in the literature and practice of science such as the determination relative permeability curve of water-CO2 using equilibrated carbonated brine and the system modeling using GEM/CMG.
Casing Failures in High Temperature Geothermal Wells: An Analytical Study
Authors: Kang Yongfeng , Samuel Robello , Kumar Vagish
Published: September 2022

In geothermal wells, temperature effect plays a very important role because of its high and cyclic temperature operation, usually in the range of 150 °C to 450 °C. Casing designed for traditional oil and gas production cannot be simply used in geothermal wells because of their different working conditions in these two scenarios. Thus, a robust design methodology for the geothermal casing is important from both economic as well as safety perspective.

Various studies have reported that the single most common failure in high-temperature geothermal wells is the mechanical overload of casing string due to constrained thermal expansion. In this research work, the classical Holliday approach for the post-yield design is reviewed and modified to include the effects of thermal yield strength deration effect and Bauschinger effect in the design process of high temperature cyclic loading encountered in case of geothermal wells scenarios.

In this study, the influence of thermal deration of yield and the Bauschinger effect on the allowable stress window is investigated. Empirical relations are used to estimate the reduction in the allowable stress window. In this research work, it has been found that the thermal derations effect and Bauschinger effect cause significant reduction in the allowable stress range. A reduction of 30% in the allowable stress window is observed due to these two factors from a case study. So, these two effects should be properly considered when doing a casing design for geothermal well.

Holliday approach ignored several effects due to the high temperature cyclic loading occurring in case of geothermal wells. This research work has addressed the limitations of the Holliday's classical approach to include these effects to make the design more robust for the geothermal well tubular design.