bluuebunny/crossref_metadata_2025 huggingface dataset:
ESP Run Life Increased by 230% Using a Small, Customized Device: The Next Step in Flow Assurance and Chemical Injection for ESP-Lifted Wells
Authors: Andagoya Carrillo Kevin Ismael , Villalobos Jorge Luis , Sierra Osiris , Correal Alvaro , Quinzo María Elena , Orozco Andrés , Enriquez Luis , Reyes Carlos , Leon Fernando
Published: October 2022

Carbonate scale is a mineral deposit transported by produced water, and its presence negatively affects well production and electrical submersible pump (ESP) performance. Instead of attempting to remediate it after it has already accumulated, a suitable and more-cost-effective process is to use a continuous inhibition treatment through an additional hardware installed in the ESP. An acid treatment can be suitable for certain types of scale, but acid treatments can cause damage to the tubing string and the ESP if not handled properly.

A new hardware was developed and used in ESP applications by looking for inhibition in fouling fluids as soon as the fluid comes out of the reservoir and before considerable pressure or heat changes occur by increasing the contact time with the treatment and by looking for a faster homogenization between the reservoir fluid and the inhibitor treatment with a 360° tool injection.

An analysis of historical data demonstrates a significant increase in ESP mean time between failure in wells dealing with fouling fluids where the tool, a tail pipe with a multipoint centralizer, was implemented. Additionally, a more-stable downhole parameter condition was reached.

It was also observed that, depending on where the tool was placed, production improved by postponing the buildup of deposits at the reservoir face and mitigating skin damage. This hardware, which improves flow assurance, has been continuously improved, and each step will be covered. Additional information was retrieved during the analysis performed during teardown of the ESPs, and it has been possible to identify wells dealing with similar problems. Some wells were newly categorized as problematic, and several data suggest that the increase in water cut related to a waterflooding process could have changed the fluid properties. By understanding the specific cause of the ESP failure let us understand that there was a direct relationship to a lack of an effective chemical treatment, not related to the formulation or dosage of the chemical treatment, but because of the challenging well trajectory due the mechanical configuration or for uncertainties in the producing fluid properties. It was necessary to create alternative tools as new solutions to improve flow assurance.

This project will provide an alternative solution that is cost effective and provides a tangible value to projects in which flow assurance and effective chemical treatment are effective when dealing with harsh fluid properties or the behavior of the fluid is unknown before ESP installation.
Emulsion Interface Model – From Science to Implementation
Authors: Vai Yee Hon , Deguillard Estelle , Mohd Saaid Ismail , Chin Hsia Ivy , Mohd Fauzi Noor Amira , Van Male Jan , Handgraaf Jan-Willem
Published: October 2022

Using computational chemistry solutions, a practical software tool is developed to simulate emulsion system, thereby gaining comprehensive information from atomistic level to manage oil field emulsion. The software tool is a revolutionary emulsion interface model, established based on physical chemistry of surface tension and torque concepts, coupled with solution of interface bending rigidity with relation to interface energy. With solid theoretical foundation, the tool is reliable and proven for field application. The emulsion interface model simulates emulsion behavior in molecular dynamics to predict emulsion type and stability in the presence of various surface-active agents. It comprises of two key mathematical approaches. The first approach is used to assess the surface mechanical coefficients (surface tension and torque) to infer the type of emulsion formation: water-in-oil emulsion, oil-in-water emulsion or microemulsion. The second approach is used to estimate the emulsion interface bending rigidity to deduce interface stability. Digital oil model with accurate representation of atomistic components of actual crude oil is constructed as input to the simulation. The emulsion interface model is verified with both published data on pure oil emulsion system and with actual data on oilfield emulsion system from offshore field in Malaysia. Good agreement between simulations and field results is achieved. This indicates that the main characteristics and physics of emulsion behavior are captured correctly in the emulsion interface model. The duration for selecting effective surface-active agents to manage oilfield emulsion can be reduced up to 90%. The main advantage of the tool lies in its dual-functionality applicable for both emulsifier selection for enhanced oil recovery and demulsifier selection for production flow assurance. Ultimately, the application of emulsion interface model has successfully enabled step-change in oilfield emulsion management via an efficient and reliable scientific based digital platform. It is a powerful tool with potential to exclusively use simulation to design molecular composition of surface-active agent for novel chemical production.
PDO's First Advanced Process Control Technology Optimizing Condensate & LPG Production
Authors: Al Humeid Mohammed Mustafa Ali , Al Musalhi Abdullah Khalfan Salim , Al Mawali Salim Hamed Thunaiyan , Sharma Vinay Kumar , Al Jahdhami Khalid Mohammed Sulaiman , Al Hamer Ahmed Abdullah Nasib
Published: October 2022

Condensate production needs to be stabilized before exporting it. True Vapor Pressure (TVP) is the standard measure for condensate volatility and is used for Condensate product specification.

Petroleum Development Oman (PDO) exports condensate with a TVP limit below 100 kPa. Whenever the limit is violated, Condensate production is automatically diverted to an off-spec tank for re-processing to bring the TVP below the limit before exporting it. Liquified Petroleum Gas (LPG) is also produced from the volatile condensate with C3 mol% and C5+ mole% specification limits below 18% and 2% respectively. Optimum operation is a point where condensate production is maximized up to the TVP specification limit at the expense of LPG production, and LPG production is maximized up to the specification limits at the expense of flash gas production. The higher the TVP the higher the condensate production, and the higher the C3% the higher the LPG production. However, due to complex process dynamics (excessive time delays between causes and effects) and limitations of the base-layer control systems (the standard setup used in PDO) in dealing with such dynamics, it is practically impossible to continuously perform corrective setpoint changes by the operator. Therefore, the margin between the TVP maximum operating limit and the actual operating point was maintained conservatively at 80 kPa to absorb the variations in TVP without violating the limit and initiating offspec mode.

Advanced Process Control (APC) is an established digital technology that has been deployed successfully in the process industry for decades to handle such scenarios and maximize the output of similar processes without violating any limits. The technology employs a predictive model of the process dynamics to anticipate changes before they happen and apply corrective actions proactively to maintain a steady and optimal operation.

The feasibility study to implement APC for the condensate Stabilization System was concluded in December 2020 and showed that APC will yield an economic value. The APC application was then designed and commissioned in October 2021 with 100% in-house capabilities and have resulted in benefits in line with the estimations of the feasibility study. The success of APC implementation in PDO opens up the door to upstream specific applications to solve optimization challenges that were not possible to solve using existing standard control system (DCS). Figure 1 demonstrates the benefits gained from deploying APC for the Condensate Stabilization System.

Figure 1 Demonstration of APC Benefits
Unlocking the Potential of Slug Control Deployment Using a Newly Developed Foam Chemical
Authors: Sagar Siti Fatimah Sarah , Hendraningrat Luky , Halim Nor Hadhirah , Rodzali Azmeer , Chai Ching Hsia Ivy , Riyanto Latief , Baharuddin Salina
Published: October 2022

The slug flow regime typically forms during multiphase flow in subsurface and surface facilities, which can result in severe flow capacity losses. The foam injection is a proposed method to control and remove slugging in the wellbore and nowadays, the foam application has been extended to controlling the slugging in the pipeline transportation. Prior to a pilot deployment in an offshore Field "S", this study describes a technological assessment review of a newly designed internal foam chemical to control slugging.

This application for controlling foam slugs aims to eliminate hydrodynamic slugs that constantly form at Field "S" due to wave instability at gas-liquid flow rates. Based on liquid level trending at surface facilities platform of Field "S", a slug flow regime was observed from severe fluctuation trending. Technology assessment was conducted using inhouse guidelines that aim to shorten overall pilot deployment to initiate testing as early as possible. The laboratory experiment was performed including compatibility tests. The foam stability and interfacial tension (IFT) were carried out using Teclis Foamscan and Grace spinning drop tensiometer, respectively. Meanwhile, the rheology characterization of foam was conducted using a Foam rheometer for the viscosity test.

A slug flow regime was discovered based on severe fluctuation trending at surface facilities platform of Field "S" for liquid level trending. Utilizing internal guideline designed to hasten the entire pilot deployment and start testing as soon as possible, technology assessment was done. A pressurized foam Rheometer was used to measure the foam dynamic viscosity, and it measured about 5.2 cP at a shear rate of 1000 s-1. The IFT measured lower than with water and other commercial foamer. When the foam chemical, defoamer, and demulsifier were tested for compatibility with production chemicals such scale inhibitor, corrosion inhibitor, and biocide, neither precipitation nor separation was seen. The recently developed foam chemical may help to further reduce corrosion from 0.17 mm/y to 0.05 mm/y. The technical, operational, health and safety, and environmental major unknown elements of this newly designed technology have all been evaluated and identified. Foam created by foam injection is a main challenge with this method, but it has been overcome by finding the right demulsifier and defoamer.

Based on this study, a newly developed foam chemical has been identified as a potential to be deployed in reducing liquid slugging in the pipeline. If slugging can be effectively controlled, value creation will result from an increase in gas and liquid production as well as the avoidance of pipeline maintenance and repair.
A Multi-Layered Strategy to Manage Foaming in Ultra-Sour Gas Sweetening Units
Authors: Al Ali Eman , Srinivas Ravi , Kaleem Jawwad , Srivastava Ganank , Shehata Mostafa
Published: October 2022

Foaming is a major operational occurrence seen in gas sweetening units; causing production losses, off-spec product, solvent losses, equipment corrosion and excessive consumption of anti- foam chemicals. Foaming can therefore shutdown an entire unit if mismanaged.

This paper details a multi-layered bulletproof strategy to manage foaming while operating and designing ultra-sour gas sweetening units. Process simulation models of an operational amine unit at ADNOC Sour Gas (ASG) were built to showcase the positive impacts of each of these recommendations on the performance of the unit. This multi-pronged guideline that adds a safety-net around the upstream separation equipment, sour feed gas, lean amine, and absorber include: (1) Internal modifications to the upstream feed gas separator; (2) Fail-safe design practice around feed separator; (3) Recalculation & modification to the conventional 5 degC temperature approach rule for the lean solvent & (4) Robust differential pressure measurement across absorber.

The above recommendations demonstrated a CAPEX and OPEX saving of US$ 25 MM and US$ 0.6 MMPA respectively to ASG. In addition, reduction in process upsets and pressure drops in the gas circuit generated production related revenues of > US$ 2 million/yr.
Ultrahigh H2S Well-Testing Operations Using Automated Surface Solutions
Authors: Alkhuwayr Asim , Karunakaran Prasad , Malik Mazhar , Youssef Mostafa
Published: October 2022

Automation of surface well-testing solutions has enabled the oil and gas industry to safely explore and produce high-risk wells and formations with unprecedentedly high levels of process assurance and quality.

Surface well-testing operations are regularly performed throughout the lifecycle of oil and gas wells to evaluate potential reserves in exploration wells initially, and later to monitor changes in well or reservoir parameters in producing wells. The collected information is critical to optimizing hydrocarbon asset management.

Such surface well-testing operations present risk associated with control, evaluation, and disposal of produced hydrocarbon at the rig/wellsite. Additionally, these operations can be demanding in terms of manpower because considerably large crews are necessary to operate equipment safely and efficiently.

Furthermore, risks are elevated when high levels of hydrogen sulfide (H2S) gas are present in well effluent because it can present imminent and elevated hazards to personnel health and equipment integrity.

To help address risks associated with high H2S concentrations in an exploration well located in a remote desert location, A new automated surface well-testing technologies for automated control and operation of critical surface well-testing equipment was recently deployed. Incorporated as part of this automated process was a zero-emission gas sampling and analysis technology. Additionally, new criteria for equipment selection and acceptance were adopted to help reduce risks to as low as reasonable when flowing hydrocarbon at the surface with such ultrahigh concentrations of H2S.

Using automated well-testing, sampling, and analysis technologies enabled the safe and efficient completion of three well tests with observed H2S concentrations up to 40% while reducing crew size and removing them from the red-zone area; there were also zero emissions in the working area.
Hydrogen Stress Cracking Resistance of Seamless Pipes for Hydrogen Storage and Transport Applications
Authors: Thebault Florian , Designolle Vincent
Published: October 2022

With an increasing number of projects involving production and use of low-carbon hydrogen, the compatibility with hydrogen gas of assets for storage and transport shall be guaranteed. Indeed, hydrogen is a threat for steel equipment integrity as it promotes subcritical crack growth. In this paper the fracture toughness resistance of a selection of seamless pipes and girth weld for pipeline, OCTG and pressure vessel in pure H2 is investigated. It covers a large variability of materials in terms of microstructures (ferrite-pearlite, bainite, martensite) and yield strengths (from 400 MPa to 700 MPa). Recommendations and requirements provided by ASME B31.12 standard have been followed for this qualification program. Fracture toughness evaluations were performed via fatigue pre-cracked bolt-load specimens exposed to 100 bar hydrogen gas during 1000 h at room temperature. All materials presented hydrogen stress intensity factor thresholds KIH largely above 55 MPa.m1/2, compliant with the ASME B31.12 option B requirement that defines materials requirements for hydrogen service. Data provided can be used for building Failure Assessment Diagram, decisive tool for predicting the safe domain of usage of structures.
Investigating Integrated Chemical Treatments for Iron Oxide Removal in Water Injection Operations
Authors: Al-Ibrahim Hussain Abdullah , Alhamad Luai Abdullah , Alnjaidi Mohammed Ahmed , Alsalem Ali Hussain
Published: October 2022

Quality of water used for injection is a very essential factor in preventing/minimizing formation damage potential due to scale precipitation. Various components in produced water such as H2S, suspended solids, bacteria and other metal ions such as iron are the primary cause of permeability impairment. Injected water should be compatible with both rock and formation fluids, thus the need to find chemical solutions to minimize the impact of injection water on formation rock arises. Potassium Permanganate (KMnO4), and Citric Acid based treatments are experimentally investigated to effectively improve water injection quality and minimize formation damage.

Extensive experimental methods were conducted to determine the optimum treatmentpercentage required to reach optimum water quality, with least amount of scale precipitants. Water samples with high salinity, iron content, sulfates and bicarbonates were used in this study. Additional experimental methods including HT/HP compatibility tests and coreflooding experiments were conducted to evaluate the impact of adding KMnO4 and Citric Acid onformation water and formation rock permeability. Compatibility and coreflooding tests were conducted on different water mixtures to optimize a water mixture having less damage on formation permeability. Experiments were conducted at temperatures up to 250°F and pressure 3,000 psi. Post treatment damage mechanisms were also investigated using XRD and ESEM methods on formed scale due to fluid/fluid and rock/fluid interactions.

The experimental investigation yielded that KMnO4 would reduce the iron content, therefore, eliminating possibility of formation damage. Oxygen scavenger was also added to some water mixtures to halt iron precipitation. HT/HP compatibility test results indicated that no iron oxide precipitation occurred in examined water mixtures after KMnO4 and oxygen scavenger were added. Coreflood experiments showed no permeability reduction in the core plugs although with white solid precipitation noticed on the face of the plugs which was attributed to the precipitation of the insignificant amount of CaCO3 as indicated by ESEM and XRD analysis. Citric acid-based recipe, on the other hand, yielded varying results with different water samples. Some cases showed somehow good water quality improvements with low iron content and others did not with high iron content.

This paper presents an experimental approach to treating and optimizing the quality of water intended for injection using KMnO4, or Citric Acid. XRD, ESEM analysis and compatibility and coreflooding experiments were conducted to assess impact of interaction of different water/water mixtures on clastic and carbonate core plugs permeabilities. It also investigates different formation damage mechanisms associated with water injection.
Low-Cost Multi-Phase Flow Metering and Assays Technology Using Online Magnetic Resonance
Authors: Deng Feng , Liu Huabing , Chen Shiwen , Chen Guanhong , Wang Mengying , Liu Chao , Shi Junfeng , Jiang Weidong
Published: October 2022

On-line, in-situ, and simultaneous detection of wellhead multiphase flow metering and assays is considered to be the best solution to obtain the above-mentioned complete information. However, due to technical limitations, currently wellhead measurement and testing are two different procedures, using different detection methods and even assigning them to different technicians. Online Magnetic Resonance (MR) is considered to be a technology that can effectively achieve molecular-level detection accuracy of oil & gas production measurement and assay after gamma ray technology, and is more environmentally friendly than the former. This work breaks through the flow measurement and testing methods of MR technology, innovates the MR magnet and antenna structure, develops a highly integrated intelligent spectrometer system, and realizes a miniaturized MR multiphase flowmeter (MRMF Smart). The low-cost portable MR tester (MRI Egg) highly integrates MR magnets, imaging coils, and spectrometers to realize multiphase flow in-situ sampling and rapid testing. The realization of this technology not only "moves" the fluid laboratory to the wellhead, but also enables MRI Technology is no longer synonymous with "expensive". MRMF Smart has carried out various tests in 100+ wells in China, the application objects cover conventional and unconventional oil and gas wells, and the application scenarios cover metering rooms, single wells, platforms, and oil and gas testing. The liquid phase measurement error is less than 5%, and the gas phase measurement error is less than 10%. MRI Egg has carried out various tests in 80+ wells in China, application scenarios include water content analysis, fluid composition analysis, viscosity detection, imaging analysis, solid oil content analysis, etc. The realization of the technology has combined the oil & gas metering and assays procedures into one, and jointly develops in the direction of high efficiency, accuracy, green low carbon and low cost.
IMGESA (Integrated Meteorological and Geohazard System Advisory) as Predictive Analytics Tool for Managing Geohazard Impacts to Pipeline
Authors: Rohani Muhammad Joehan Bin , A. Rahman Azam Bin , Abdullah M Syazwan Kamil Bin , Ali M Nazmi Bin , Putra I Wayan Eka , Hidzir Hazwani Binti , Amirian Ehsan
Published: October 2022

There is an industry need to have a fit for purpose whilst accurate method of predicting geohazard impact to pipelines. Geohazard events are influenced by rain occurrences. The effect of rain intensity and duration has been much researched in the context of understanding slope failures in Malaysia's context, however timely prediction of slope failures triggered by rain events that can cause pipeline damage remains challenging.

The major challenge arises from the fact that numerous variables influence the prediction of the target parameters called PR (Risk Index for geohazard impact to pipeline) and pipeline strain predictions. Uncertainties that makes prediction challenging includes but are not limited to soil strength parameters, subterrain geological conditions, occurrences of external disturbances that are outside zone of concerns and also numerous pipeline related parameters that renders understanding influences complex.

To further enhance timely and improved accuracy of predicting geohazard impact to pipeline, new Machine Learning capabilities were used to develop a tool called IMGESA (Integrated Meteorological and Geohazard System Advisory) leveraging on probabilities method to study the features of terrain degradation that are impacted by rain intensity and its duration. New probabilistic algorithms can be used to manage uncertainties. Machine Learning methods can provide the basis for continuous improvement to predictions.

Two main parts in establishing the impact of geohazards to terrain degradation are discussed in this paper: the first is associated with availability of data, namely which data can be considered as main influencer to terrain degradation; the second is associated with development of methodology in establishing the predictive model of PR (Risk Index) and Strain Prediction that can be acceptable by industry.

This paper will explore the issues from these two important parts and will present salient Machine Learning related experiences to provide the much-needed technology enhancement to push the needle in predicting terrain degradation and its impact to onshore assets.
Developing Comprehensive Predictive and Prescriptive Management System for Flexible Pipeline Survivability
Authors: Jaafar Azam Syah Bin , Hussien Hayati Binti , Ali Noor Razak Siti Aishah Binti
Published: October 2022

In 2020, PETRONAS had lost a flexible pipeline due to an increase level of contaminants in the process stream, which carries into the flexible pipeline system. The incident had caused a major cost impact in which the pipeline needs to be replaced and the production had to be differed for at least 1-year. Detail investigation was conducted, and the finding indicates that amongst the root cause was the unavailability of proper predictive and prescriptive approach in managing flexible pipeline integrity system. Thus, this had triggered PETRONAS to embark an initiative to develop a Flexible Pipeline Management System, which then will be included and further developed alongside with PETRONAS digitalization journey.

PETRONAS Flexible Pipeline Management System will be developed by upgrading the existing PETRONAS Digital Management System for carbon steel pipeline. As an overview, scopes for the Flexible Pipeline Management System are comprises of guidelines development, risk parameters establishment, fitness for service (FFS) assessment method advancement, and flexible pipeline remaining life extension study (FLES). Its development started with leveraging on PETRONAS experience in carried out integrity assessment for the existing flexible pipeline with expired design life using analytical method.

The assessment was conducted in collaboration with flexible pipeline integrity experts which had been included as part of PETRONAS capability up skilling program. Progressively, the flexible pipeline integrity management guideline, risk assessment protocol, and predictive assessment method for FFS and PLES were developed and corelated within.

The above elements had been grouped and formed as Flexible Pipeline's integrity assessment manual. It has then been piloted to one of PETRONAS existing flexible pipeline and turned out very successful. The pilot had resulted in eliminating the need of pipeline replacement and generated cost avoidance of more than USD10 Mil - by assessing the remaining life of the pipeline, managing the risk failures through inspection and monitoring plan, as well as minor repair(s) whenever specified.
Iron Sulfide Chemical Dissolver Deployment in Water Wells
Authors: Al-Hajri Nasser M , Ureiga Sulaiman T , Javed Muhammad Imran , Marri Saleh J
Published: October 2022

This paper will introduce a pioneering Iron Sulfide (FeS) chemical dissolver. The novel chemical dissolver can be used for descaling applications in oil and gas wells. However, the particular scope of this paper would be to outline an operational well intervention workflow for a successful deployment of FeS dissolver in water wells.

Iron sulfide scale presence in the wellbore is challenging to oilfield operators. Unlike other common scale types, such as Calcium Carbonates, FeS scale does not dissolve easily in Hydrochloric Acid (HCl) and the FeS/HCl reaction produces the dangerous Hydrogen Sulfide as a reaction product. Accordingly, oilfield operators resort to mechanical descaling of the FeS in order to restore wellbore accessibility. Mechanical descaling has disadvantages that include high cost, the need to flowback downhole milling returns, and possible damage to downhole tubulars. Alternatively, the novel chemical described in this paper can be used to effectively descale the wellbore without exposing the oilfield operator to the setbacks that could encountered from mechanical descaling. This paper will outline operational steps to execute a flagship descaling operation. The operational steps include pre-job diagnostics, job design and contingencies, as well as expected results and outcomes.

The proposed FeS dissolving chemical has successfully met all laboratory and field criteria to descale iron sulfide scale and stimulated well injectivity. The deployment of the FeS dissolver can result in 67 % increase in overall well injection rate compared to pre-chemical descaling rate. Other tangible benefits to this chemical include avoidance of rig workover operations to pull and replace downhole tubing in cases where mechanical descaling was not successful in restoring wellbore access. The new chemical allows for conducting safer descaling operation by reducing risks associated with reproduction of hydrogen sulfide, formation damage from non-friendly chemicals, and downhole equipment damage by corrosion. The chemical also has the ability to dissolve carbonates for near wellbore cleanup. The dissolver has a 70 % enhanced dissolving ability comparing to 15% HCl.
Oil Rim Development by Waterflooding: Lessons Learned from the South Turgai Basin Case Studies
Authors: Mukanov Adil
Published: October 2022

Characteristics of two brown oil fields in the South Turgai Basin Field pose challenges for field development. Oil rims bounded by a gas cap on one side and an aquifer on another side are present in both fields. These features coupled with poor rock properties make the development of these fields challenging. As a result, enhanced recovery techniques are necessary for the economic production of oil and gas.

Accounting for high saturation pressure and weak aquifer reservoir pressure maintenance is considered critical for the oil rims, as these have been observed twofold reduction in reservoir pressure from the initial one. To account for such effects, previous producing wells were converted to gas and water injection wells. Gas flooding of the gas cap is performed using a crestal injection pattern and water injection into the gas-oil zone is used to create a water bank between the gas cap and oil rim. Moreover, waterflooding is launched by peripheral water injection with additional advantages attained from gravity segregation.

Changes in oil and gas production have been observed as a result of pressure maintenance. First, the gas injection implemented in the wells located 1.5-3 km from the oil rim have prevented gas breakthrough in producers, despite the significant injection rates. High injection rates are a result of the governmental ban on flaring, since this prompts engineers to perform faster pressure recovery and target a higher volume of utilization. Second, crestal and edge water injection have different results in different parts of the fields. However, in some cases rim flooding have devastating effects as producers have been watered out. On one hand, the goal of decreasing the gas production was met, which happened earlier and was one of the biggest challenges facing the company. Consequently, gas-oil ratios decreased almost ten times than what they were previously. On the other hand, water-cut on many producers increased substantially, up to 90-95%, and in some areas top injectors even killed the down-dip producers. Thus, despite having solved one problem, another one emerged. Overall, crestal water injection (i.e., barrier waterflooding) is risky, and requires stricter regulation and management.

Case studies from the South-Turgai Basin show that water injection in top structure of oil rims for enhanced oil recovery can lead to positive as well as negative results. Overall, the paper demonstrates the cause-and-effect relationship of the previously described impacts of such water injection and provides recommendations for proper waterflooding management in oil rims based on the success in other parts of the field.
Case Study of Successful and Optimal Strategy to Test and Evaluate Three Target Reservoirs in Single Exploratory Well
Authors: Siddique Faisal Anwar , Aslam Muhammad Adeel , Khan Imran , Abbasi Yasir , Khan Zaid , Hasany Syed Tariq
Published: October 2022

A case history of an exploratory well in Lower Indus basin in Pakistan, is described where Massive Sand Deep, Massive Sand Shallow and Basal Sands of Cretaceous Lower Goru formation were target reservoirs, however, during drilling, positive indications were also observed in Sembar formation of early Cretaceous age.

Successful formation evaluation of three target reservoirs posed a great challenge, due to bad hole conditions and bad cement job. This resulted in risk of no formation zonal isolation between target reservoirs along with risk of operational issues due to high mud weight.

The strategy was adopted to test and conclude each reservoir with marginal potential, as such, other reservoir formation evaluations were not compromised. Decision tree based methodology was extensively used to convey the plan, which really proved helpful and avoided confusions for all shareholders and decision makers.

A thorough critical analysis of previous formation testing/Drill Stem Testing (DST) jobs and their success rates were performed. Analysis of cement logs, mud and wireline logs were performed to select best evaluation jobs for respective targets. Similarly for formation testing jobs, zones of interest needed further optimization considering zonal isolation and presence of cement behind pipe.

The testing strategy resulted in the best possible formation evaluation and finally conclusion of all three targets reservoirs. With this, cost optimization was achieved as all targets were tested in single well. Use of decision tree was successful in conveying status and way forward at each step, which avoided confusion in all shareholders. Also, as future way forward was already put in place in form of decision tree, based on encouraging/ disappointing results, everyone involved knew about the course of plan. Integration of all available technical data was very critical which helped maneuvering in taking decisions. The strategy became so successful, that shareholders advised to make it part of every new project.

This project presented and prompted company and joint venture partners, the valuable use of flow charts and decision trees and proved to be an excellent tool to convey information, to stay aligned and to be aware of future strategy.
Hydraulic Fracturing QA QC Indispensable to Delivering Both a Successful and Economic Fracture Program
Authors: Al Salmi Hussein , Al Shueili Ahmed , Jaboob Musallam , Al Qassabi Mohammed
Published: October 2022

It is well known that close quality assurance and quality control (QA/QC) are of vital importance for the successful placement of any hydraulic fracturing treatment. Many complex pieces of equipment and specialized personnel are involved in the fracturing process, and the following of strict QA/QC standards is mandatory to make these operations successful, efficient and safe. BP Oman is using massive hydraulic fracturing treatments to exploit the challenging tight-gas Barik Formation in the Khazzan and Ghazeer Fields. Each treatment is designed to place 1 million pounds of proppant into this tight, high pressure high temperature reservoir, leaving no space for error.

Implementing QA/QC and logistic supply measures begins with the mobilization procedures: chemicals checklist/verification and mixing on the base, timely equipment maintenance, bulk plant proppant delivery to ensure a swift and smooth 24 hour operation. Water delivery management loading quality check, logistics, site acceptance and minimum quality checks are another important procedure related to this preparation. Each fracturing stage requires at least 14,000 bbl of fresh water to be available and quality checked on the site before the start of the fracturing treatments. Intensive QA/QC measures continue through the day of the fracturing treatment itself to ensure the equipment is in full working condition. Assurance that all of the supply systems are properly calibrated, all chemicals loaded and levels physically measured. During the fracture treatment itself all parameters are repeatedly measured and visualized in real time. Fluid viscosity is assessed on the fly and data verified with an HPHT viscosimeter also present on the wellsite. After the treatment, all remaining chemicals are measured once again and carefully assessed against the expected inventory values and material balanced.

Implementing extensive QA/QC procedures enabled efficient mobilization between wells with mobilization time as low as 6 days despite the complex equipment and material needs for these massive fracturing treatments. Planned logistics and consistent quality checks before, during and after the treatment enabled BP Oman to successfully place more than 100 hydraulic fracturing stages with the amount of proppant exceeding 1 million pounds per stage. The bar has raised even higher with successful placement of 2 million pounds of proppant, the largest single stage hydraulic fracturing treatment in the Eastern hemisphere at the time of execution.
Optimization Experience on the Use of Carbon Steel Tubing for Sweet Corrosive Gas Field
Authors: Mitraningsih Farih , Styward Boris , Tokoh Kristoforus Widyas , Angela Irene
Published: October 2022

CRA 13%Cr has been used at all Mahakam swamp and offshore gas wells since 1990's for oil country tubular goods (OCTG) particularly for production tubing, due to its excellent CO2 corrosion resistance. By mid of 2000's, when depletion observed in one reservoir level, the new production started from different level, thus reduce the wells design life and increase the completion job frequency. To avoid completion delay due to tubing material delivery, CLAS 3%Cr and Carbon Steel (C-steel) tubing were proposed. By late 2010's, the study was done to develop materials selection guidelines to provide necessary information allowing early selection of the most appropriate and cost effective Steel for lower well completion. And finally, since 2015, C-steel tubing has been applied to all entire tubing (lower and upper completion a few hundred meter below safety valve) on sweet corrosive gas well through systematic corrosion and erosion assessment, which has been verified as well by tubing wall measurement logging. This paper summarizes the outcome of several studies has been done, and demonstrate the optimization on the use of C-steel tubing instead of higher grade material, as part of corrosion management strategy to synchronize fit for service and economical objective.
Applied Framework for Managing Sustainable Retrograde Gas Condensate Reservoirs
Authors: Tawfiq Rowa , Alahmadi Asma
Published: October 2022

Managing retrograde gas condensate reservoirs comes with its set of challenges. To maximize recovery and ensure the sustainability of reservoirs, the reservoir engineer must ensure the proper well placement, choose the best completion, and perform regular reservoir surveillance. This paper discusses an applied framework for managing retrograde gas condensate reservoirs, to ensure the longevity of the reservoir and maximize performance.

The process of managing sustainable retrograde gas condensate reservoirs entails proper well placement, which can be achieved through an in-depth assessment of the targeted geological formation in terms of reservoir development. This is further assessed through acoustic impedance maps, seismic data, and any reservoir modeling available. Also, choosing the correct completion of the well is a function of the information obtained from well logging and sampling. Finally, proper reservoir surveillance should be implemented after the well is put on production. Information such as pressure and temperature data, zonal production contributions, and pressure build-up tests should be obtained regularly.

Following proper well placement, correct completion choice, and regular reservoir surveillance can aid in maximizing production and ensure the sustainability and longevity of the reservoir. Utilizing a comprehensive geological model to study both the structure and development of the reservoir can aid in choosing the optimum well type: vertical, horizontal, or deviated, as well as the required completion. Once well logging and sampling are performed, an optimal completion method can be deployed. Typically, porous sandstone reservoirs require some sort of sanding control method to not impede the production of gas. Tight gas reservoirs would require fracking to increase permeability, and sand control to reduce sand production. As an alternative, tightness can also be overcome by drilling horizontal wells with high inclination to increase reservoir contact. Finally, reservoir surveillance is of utmost importance for retrograde gas condensate reservoirs. Reservoir fluid characterization aids in determining the dew point pressure, after which condensate starts to produce. Several methods are discussed to reduce the effect of condensate production.

This paper discusses a framework for managing a retrograde gas condensate reservoir, where successful planning, completion, and surveillance can be applied. The article also sets forth a flow chart to exemplify the optimum path to manage and sustain retrograde gas condensate reservoirs successfully.
Successful Intervention into a Six-Leg Multi-Lateral Well Using an Electrical MultiLateral Tool Deployed on Real-Time Hybrid Coiled Tubing for Acid Stimulation of a Kuwait Field - A Case Study
Authors: Bastaki Fahad , Al Matar Mohammed , Omar Mizan , Barki Jassim , Jamal Mariam , Al-Mutairi Fayez , El-Aziz Sabry , Albahar Zakaria , Al-Mehena Mehanna , Khandelwal Nakul , Chawla Sapna , Gaur Rishika , Alkreebani Mohammad , Travesso Joshua
Published: October 2022

Multilateral technology offers multiple benefits to oil and gas operators, including lowering the field development cost by minimizing wellsite construction work and increasing reservoir contact leading to enhanced reservoir production. To gain full advantage of these complex wells, they must be stimulated properly.

The operator in Kuwait drilled, cased, and cemented a six-leg, level IV multilateral well targeting two different formations, the upper and lower Tuba. This provided various production options and the flexibility of taking production from either the lower or upper laterals or even all six laterals to help mitigate the risks of drilling horizontal or directional wells. As such, multilateral technology can positively transform the economic viability of reserves in marginal fields. Exploiting the advantages of multilateral technology requires a multi-disciplinary approach to select appropriate well structure, completion design, re-entry flexibility, and production longevity.

Intervention in this level IV multilateral well presented several challenges, such as Oil Based Mud (OBM) in all the laterals, encountering a fault in one of the laterals while drilling, and high shale content that can lead to stuck Coiled Tubing (CT) and the loss of fluid returns. Real-time hybrid cable CT was chosen along with an electric multilateral tool to mitigate the various risks involved. This solution includes a hybrid fiber optic and electrical cable installed in the CT string and a modular Bottom Hole Assembly (BHA) equipped with various sensors. An electrically controlled indexing tool, inclination sensor, tool- face sensor, downhole camera, hydraulic knuckle joint, and pulsating stimulation tool were used as part of the BHA to enable real-time diagnostics and dynamic controls from the surface to successfully enter and stimulate all the lateral legs. This configuration helped identify each different lateral without the need to tag the bottom of each lateral. The paper focuses on applications, strategies, and benefits of specific tool configurations developed for multilateral well intervention, enabling the stimulation of all the lower Tuba laterals. This was a particularly challenging operation due to shale in one of the laterals causing several instances of stuck CT with the possibility of a collapsed hole mitigated by using the real-time camera in the BHA.

This paper includes strategies that address proper tool selection, confirmation of lateral entry, hydrostatic pressure balance, borehole stability, and acid design. It also explores the potential of new, synergistic strategies and work processes planned for stimulation of the upper Tuba field.
Time-Lapse Pulsed Neutron Logging Helps Maximize Recoveries from Mature Field - Case Study from Mangala Field of Rajasthan, India
Authors: Kumar Alok , Sigtia Shraddha , Das Joyjit , Guha Rupdip , Ahmed Abaan , Shankar Vivek , Kumar Suresh , Chauhan Nishi , Kumar Ravinder , Ramakrishna Sandeep
Published: October 2022

Mangala Oilfield of Rajasthan has produced over 36% of STOIIP and has been subjected to several innovative and new era technologies since it started producing in August’ 2009. Initially, field was under Water flood phase till April’2015 and then full field Polymer flood phase started to maximize recovery. Mangala field with medium-gravity viscous crude oil & formation water salinity of approximately 8000ppm has an excellent reservoir property of high porosity (24 to 26%), high permeability (200md- 20D) and very low irreducible saturation i.e., less than 5%. Thus, C/O logging in this field has been a very good choice to estimate the remaining oil saturation (ROS) and understand the sweep of oil due to injection which in turn has helped in maximizing recoveries from the field.

Time-lapse PNL were run in several wells to monitor the efficacy of the water flood/polymer flood phase on oil recovery. The objective was two-fold; to estimate the change in saturation over time and to identify by-passed or marginally swept intervals. The process begins with recording the initial saturation in the wells before any production has occurred. Then time-lapse data are recorded to monitor the change in saturations. Secondly, saturation estimation from PNL data were used to plan the next course of action- workover operations, changing completion zones, abandoning certain zones or wells, and infill drillings. PNL data in combination with other reservoir surveillance techniques (MPLT) has proved to be a vital surveillance tool to maximize the recovery from this field.

In this paper, we present the effectiveness of PNL tool specially RMT-I with production data over a period of 3 years (post Aug 2019). However, the results also include integration of other PNL dataset (RST & Raptor) acquired for reservoir surveillance activity and the challenges involved in interpreting the result of different PNL tool over time.

In absence of RMT 3D tool, PNL is acquired as 1 Sigma up/down pass and 3 CO up passes at 1fpm-3fpm to address the uncertainty related to gas presence on C/O interpretation. Sigma measurement helped in identifying gas below packer or in the annulus behind pipe and helped in addressing the uncertainty related to gas presence on C/O interpretation. Secondly, RMT was planned in infill well post drill to determine the uncertainty between OH and Cased hole Oil saturation. The results agreed with production data and uncertainty in oil saturation estimation was minimized to 10-15% approximately. Several cases will be discussed in the paper to demonstrate the use of PNL logs for reservoir management.