bluuebunny/crossref_metadata_2025 huggingface dataset:
The Dawn of Routine Satellite-Based Monitoring for Energy Infrastructure is Now
Authors: Weaver R. Peter
Published: October 2023

Hyperspectral imagery (HSI) began in the 1980s and has been used by the U.S. government for years, but it just recently became available for commercial use. This technology has a vast range of potential applications, with oil and gas pipeline monitoring being one of the most prominent examples. HSI enables unparalleled daily global pipeline leak and change detection capabilities. This technology, deployed by satellite, is now beginning to replace conventional aerial monitoring compliance while also enabling enhanced emissions detection. This paper discusses the state-of-the-art for HSI, with examples of pipeline leaks and encroachment observed using hyperspectral data and analysis.

Successful HSI deployment will drive a decrease in the number and magnitude of pipeline leaks using frequent, global, high-resolution data collection, rapid and reliable analysis, and reporting of actionable information. This paper focuses on Oil & Gas, but the application spans industries. Across the board, HSI commonly enables use cases throughout the resource lifecycle.

For decades, satellite-based HSI technology has offered the promise of remote detection of hydrocarbons and other disturbances. It is finally becoming scalable and cost-effective for the pipeline operators and thus a reality for cost-effective asset stewardship.
Hybrid Data Driven Intelligent Algorithm for Stuck Pipe Prevention
Authors: AitAli R. , Arevalo P. , Dashevskiy D. , Mahmoud M. , Pocaterra A. , Al Bouny A. , Hussain Mohamed Qassem , Baruno Agung , Mohammed Satia
Published: October 2023

In today's drilling industry, it is essential to utilize both downhole and surface real-time sensor systems along with physics-based models to detect drilling hazards at an early stage and take timely measures to mitigate drilling related risks reducing non-productive time (NPT) and invisible lost time (ILT). Stuck pipe events are a major cause of NPT with an estimated cost to the oil and gas industry in the range of hundreds of Millions USD per year. Given its impact to drilling operations, stuck pipe prevention has high relevance and attention in the industry. In fact, in the last decade, the number of initiatives using drilling data coupled with advanced algorithms (combination of artificial intelligence (AI) and machine learning (ML)) to better understand and prevent stuck pipe events has greatly increased. Different approaches utilizing surface data are available ranging from data driven models, physics-based models, or even hybrid approaches combining physics-based models with data driven models. In any case, the outcome is an algorithm tasked with the identification of stuck-pipe events before they happen. If such an algorithm is deployed at the rig site (i.e., running on an edge device), ingesting surface and downhole data in real-time, the potential to improve the drilling process in terms of performance and safety greatly increases. Furthermore, safer drilling operations have an impact not only on the reduction of the overall capital expenditure (CAPEX) for well construction, but also on associated carbon emissions.

The approach presented in this paper is based on drilling automation applications focused on the integrity of the drilling process. The system includes a set of advanced algorithms coupled with digital twins (e.g., physics-based models of the wellbore) running on an edge device deployed at the rig site, to create a comprehensive monitoring and alert solution for surface hookload. The monitoring system consists of three main components: a reference environment given by digital twins, which provides safe operating envelopes (SOE) defined by overpull and buckling as boundaries; a set of algorithms to detect and sample common indicators of torque and drag automatically, such as pick-up (PU), slack-off (SO), rotation off bottom (ROB) torques and loads; and a higher layer to identify trends and deviations between the samples to create early warnings related to stuck-pipe symptoms.

The monitoring system implemented can be deployed for all kinds of drilling operations (i.e., drilling, tripping, circulating). By providing early warnings of stuck pipe like symptoms, the system enables users (i.e., rig crew, drilling operations, drilling optimization engineers) to mitigate such symptoms in time, hence avoiding costly consequences.
ADNOC's Approach in Piloting ESG Third Party Due Diligence Framework
Authors: Al Hameedi Samar , Al Raisi Azza , El Ghazouli Majid , Balalaa Mona Ahmed , Orsini Yadaira , Smith Courtenay
Published: October 2023

The aftermath of COVID-19 has highlighted the importance of resilient and sustainable supply chains. There is a growing body of evidence demonstrating how sustainability programmes can help companies recover from disruptions by optimising and reducing costs associated with these. Research from McKinsey shows that strong ESG performance can drive down costs by 5-10%, as companies focus on operational efficiency and waste reduction. It also shows that ESG high performers enjoy faster growth and higher valuations (Cherel-Bonnemaison et al, 2021).

Becoming an ESG top performer undoubtedly means understanding and proactively managing supply chain risks, particularly as two-thirds of an average company's ESG footprint lies with its suppliers (Cherel-Bonnemaison et al, 2021). There is no denying the value proposition that ESG brings and the key role it plays in managing risks associated to third parties. What is less clear is how to effectively integrate ESG into company-wide decision making.
Long Term Development Implications of Parent-Child Interactions in Unconventional Reservoirs
Authors: Srinivasan Karthik , Faulk Andrew Bryce , Sanders Karen Elizabeth , Guice Kyle Brandon , Ramirez Melissa Y , Mohan Lavanya , Rajput Nandini , Weisman Daniel , Malpani Rajgopal
Published: October 2023

This paper examines the impact of parent depletion on well performance of child wells in a stacked pay unconventional basin with horizontal wells landed in multiple benches. Both intra-bench and inter-bench parent-child were considered, and examples described. This paper also addresses future development implications that result from best-bench-first development in stacked unconventional plays as a function of degradation in child well EURs. This work focuses on both horizontal/vertical interference where presence of pre-existing fracs and depletion in parent wells impact fracture height growth/length and resulting productive frac size in child wells.

Two case studies were selected to demonstrate intra-bench and inter-bench parent-child degradations. In the first case study focused on intra-bench parent/child, two adjacent development sections were evaluated, each having been developed as phased developments (multiple landing targets) and with a 9-month lag in first production between the sections. In the second case study focused on inter-bench parent/child, two nearby sections were considered in which different phased development strategies were employed across three distinct landing targets. In both case studies, significant child well degradation was observed in both bottom hole pressures and well production data; observations of impacts to parent wells were also noted. These findings are further supported by modeling efforts.

Combined, these case studies indicate that both inter-bench and intra-bench parent-child are significant concerns in stacked unconventional plays, such as those found in the Permian Basin. Our attempts to fully negate the impact of parent-child through later development choices, or to develop child wells without waste, have proven unsuccessful. Complete mitigation of parent-child impacts requires both co-development of potentially connected landing targets (inter-bench) and mow-down development of adjacent development sections (intra-bench).
The Best-In-Class Implementation of Dual ESP Technology in an Abu Dhabi Mature Offshore Oil Field to Successfully Extend Well Life with Significant Contribution to Sustainability
Authors: Abdelkerim A. I , Ballah S. , Al Ameri M. , Obeid A. , Arawi A. , Sanghavi D.
Published: October 2023

A mature offshore Abu Dhabi oil field produces from a heterogeneous carbonate limestone reservoir with an important column of bottom aquifer. The reservoir heterogeneity is characterized by presence of karst filled with fine materials at top section, conductive faults, fractures, and significant variation of rock properties. As a result, the natural wells exhibit short life due to rapid water cut increase with water encroaching into wellbore from bottom aquifer through conductive faults. To mitigate this issue, the field development strategy has been revised to install ESP in all producers to sustain oil production by extending well life while maximizing operating efficiency and overall field ultimate oil recovery. Starting from 2001, conventional single ESP was successfully piloted in 4 wells, which provided run life up to 3 years on average including some premature failures. As the field has a small number of wells with limited allocated rig resources, the ESP well remains idle between 3 to 6 months after ESP failure while waiting for replacement by rig. This resulted in significant oil production volume loss and higher unit lifting cost. Hence, the field development decided to pilot dual ESP in 2015 with 2 ESPs in series with one running and another on standby in hole as backup. The objective is to reduce downtime and deferred or lost production volume while mobilizing rig and equipment for workover. Consequently, after successful piloting, a total of 6 dual ESPs were installed from 2015 to 2023 helping to extend well life by up to 2 folds, contributing to sustain production and reduce lifting cost from two to one digit. As a result, the field was able to deliver production mandate ahead of planned date and provided incentive to plan for further production increases with higher operating efficiency and lower operating cost.

This paper describes the outstanding process of dual ESP design, installation, operations, and the performance, illustrating the best-in-class artificial lift performance results.
An Autonomous Approach to Mitigate Risks Associated with Well Intervention in ESP Completed Wells
Authors: Balkhair O. M. , Afif O. T. , Aljindan A. A. , Raad A. F.
Published: October 2023

Well intervention is an essential overall part of maintaining the integrity of wells. Moreover, intervention methods can differ based on each respective well completion. For well intervention purposes, a Y shaped tool (Y-Tool) is installed which usually accommodates an ESP's completion. The proposed paper suggests a process that utilizes an Automatic Y-tool completion which eases well intervention operations. Using a blanking plug is the norm when it comes to ESP completions equipped with Y-tool where it provides a good seal and prevent the fluid from flowing into the bypass profile. Moreover, setting or removing the blanking plug can be quite challenging if any obstruction has accumulated in the bypass profile. An automatic y-tool completion can be an effective solution where it provides a reliable ball/seat seal and eliminates the risk associated with any attempts involving the installment or removal of blanking plugs. The y-check tool features a moving ball that is triggered by the flow and pressure produced by the ESP, which in turn moves the ball seal into its respective seat and seals the desired section of the completion. After the successful installation of the automatic y-tool completion, the ESP performance was observed to ensure that there is no leak in the ball/seat sealing mechanism and that it can be utilized in the upcoming well intervention operations. This paper will illustrate the challenges associated with the blanking plug and benefits introduced in the automatic y-tool. This will be reflected on the ESP performance that will ensure the functionality of the automatic y-tool, and the highly effective intervention operation that can be conducted with a system such as the one mentioned in the paper. The paper discusses the detailed process in effectively utilizing the automatic y-tool in well intervention operations, which in turn provides a more efficient alternative for well interventions in completions with an ESP installed.
Novel Plug and Perf Technique in Monobore Completion of Jurassic Gas Well in Kuwait
Authors: Al-Matar Mohammad , Theyab Abdullah , Al-Mubarak Hamad , Al-Shammari Faisal , Al-Jaber Mohammad
Published: October 2023

Various wells completed nowadays can be classified as short-life or harvest wells. Some of these would not be economically feasible using high-end completion components and methods. Monobore wells can be a solution to this dilemma. Meanwhile the strategy of Kuwait is in growth direction and demand increasing of oil and natural gas production. Consequently, the company will eliminate the requirement of the workover rigs, while enabling the selective stimulation.

A 4 ½" monobore completion well was first implemented in Kuwait in Jurassic fields. In the direction of maximizing the production while enabling the vast majority of rigless intervention operations including the plug and perf technique, full drift cleanouts and high rate stimulation. Plug and perf technique provides the ability of carrying out the selective stimulation and testing for each individual zone independently. Treatment can be tailored for each zone whether it is a matrix stimulation or hydraulic fracturing which maximizes the production and reduces the formation damage.

This paper will begin by reviewing the increasing of oil and gas production by using plug and perf technique in monobore completion wells. In addition, using plug and perf technique in Jurassic oil and gas wells, and employing the monobore completions, the number of rig based workovers diminished by a huge margin due to the ability of utilizing the rigless workover, such as: coiled tubing, wireline, slickline. These efforts reduced the cost by a massive amount as well as getting the production back online in very short time. Kuwait Oil Company can isolate each zone if they produce water easily and directly without need of using any workover.

This paper shares the successes, challenges and lessons learned from the monobore wells in Kuwait that were produced by the Plug and Perf technique, and the consequent interventions to achieve the maximum production.
Dynamic Underbalance Perforating for Production Enhancement and Frac Optimization in Tight Gas Wells: Case Study from Sultanate of Oman
Authors: Suleimani Ahmed Al , Al Hinai Adnan Saif , Nunez Alvaro , Al Rasbi Said
Published: October 2023

The objective of the paper is to demonstrate the effectiveness of the dynamic underbalance (DUB) perforation technique, especially in enhancing the performance of deep tight gas wells in the Sultanate of Oman. The technique aims to provide cleaner perforation tunnels, eliminate perforation damage, and improve flow/injection by creating a sharp, localized pressure drop across the perforation interval immediately after the perforation tunnels are formed.

The paper begins with an overview of the operation and the nature of the deep tight gas wells in the field, with particular emphasis on the tight reservoir with low permeability. It underlines the importance of combining deep penetration jet charges with dynamic underbalance (DUB) to achieve deep and clean perforation tunnels which helps in reducing the perforation skin and improving connectivity with the reservoir, contributing significantly to optimizing the hydraulic fracturing job that results in lower breakdown pressure and more successful frac placement.

This paper presents field examples where the dynamic underbalance (DUB) technique was applied in multiple tight gas wells. Details include the use of a 2 7/8" gun configuration in 4.5" completion size with a fast pressure gauge run alongside the perforation gun to measure the extent of dynamic underbalance created by the gun system. These actual measurements were then compared with estimated dynamic underbalance values derived from pre-job simulations using proprietary software. The results largely mirrored the predictions, indicating the effectiveness of the modeling process.

In most cases, we observed a reduction in the treating pressure required for fracturing. Despite high formation stresses in some wells which limited the impact of DUB, a great improvement in initial production rates was observed, compared to projected rates.

The results demonstrate the effectiveness of the DP perforation guns with DUB perforating technique in enhancing connectivity with the reservoir, leading to achieve higher production flow rates. This effective performance eliminated the necessity for fracking in the designated zone. Also, the effectiveness extends to the pre-frac perforation application in achieving breakdown and fracture placement in the ultra-strong formations of field B, where rock strength exceeds 30 KPSI. In such challenging formations, conventional gun systems often struggle to initiate breakdown pressure in these formations and abrasive jetting with coiled tubing has typically been utilized to initiate fracturing in this environment however, it is costly, big footprint and much less efficient. The adoption of DP perforation with DUB technique has substantially enhanced both efficiency and cost savings.
Improving Reservoir Efficiency by Drilling Super Slim Multilateral Wellbores
Authors: Zakirov Z. , Galiev R. , Miftahov R. , Galimova N. , Karimov T.
Published: October 2023

Oil production in brownfields has a wide variety of challenges. The brownfield operators’ main goal is to maintain desired production rates, keeping the OPEX and water cut ratio low. The small-diameter wells today are a common asset of E&P companies. Once the small-diameter wells are deteriorating in hydrocarbon production rates, the question of the financial viability of these assets’ rejuvenation is associated with high uncertainties: lack of proven simulation methodologies, formation water intrusion risks, and other challenges. This paper describes the results of super-slim laterals drilling from a small diameter wellbore. The required downhole tools were engineered to tailor small-size lateral wellbore drilling and completion-associated challenges. The newly developed technology has been also implemented to better reach hydrocarbon reserves.
Session: 47 | Health and Safety: Human Factors and Process Safety
Authors: Aslam M. , Venkatesan K. , Ahmed S. , Ketbi A. Al , Ahmed M. S. , Alshehhi K. , Haider F. , Al Mazrouei M. K.
Published: October 2023

More than 30% incidents in Oil & Gas sector involving storage tanks have been caused by human error, including poor operations and maintenance practices. Several LOPC and major accidents in Oil and gas industry have been attributed to the improper flushing and purging of hydrocarbon systems prior to handover the facility/system for maintenance or project related tie in activities. Tight shutdown plans especially in the brown field projects is major forcing factor for operation staff to cut the corners and take short cuts in order to achieve the project milestone and production mandate on time. Complexity of the piping network is adding difficulty to the problem which makes the process of isolation/flushing/purging quite time taking. Several incidents across various industries were studied as part of the assessment methodology to identify the root causes to reach the proper solution. Inadequate engineering designs adding dead legs to the system contributing to the difficulty in freeing system from hydrocarbons. This solution can be applied to any oil and gas facility for minimizing the shutdown duration and ensuring safe execution of critical activities in brown field projects execution. During design optimization and value engineering reviews of the new facilities, long terms operational impacts are overlooked, which could result in potential dead legs and unavailability of adequate isolation points.
Cost Model Optimization of Integrated Drilling Services Contracts in Delivering Economical and Fit for Purpose Development Wells for Petronas Operated Field in Middle East
Authors: Aldarkazly H. , Sze W. Han , Alam R. Rj Zainal , Ali A. Md , Yusof W. Y. Wan , Ramli A. , Affendy M. K. , Al-Shaheen H. , Mutlag W. , Marzoq A. , Alqasim M. , Jamal A. , Ismail A. L. , Nazarudin M. Bin , Johar J. H. , Hamat W. Che
Published: October 2023

Cost optimization is an ever-enduring subject in drilling industry. PETRONAS, as a prudent operator of an oil field in Middle East, constantly pursues for means in optimizing drilling cost which makes up between 50-70% of a typical development project CAPEX, ensuring the projects stays economical to PETRONAS while still delivering its production commitment and values to its stakeholders. In ensuring PETRONAS and its partners investments remain protected, all drilling operations related risk compounded with regional specific risks must be accounted for and addressed in its contracting strategy. In such situations, typically an operator would opt for a turn-key or Integrated Drilling Services (IDS) approach contract in ensuring its cost are capped. However, placing considerable risks to IDS contractor will subsequently driving the well cost up. Tailoring a fit for purpose cost model of IDS contracts is vital in striking the balance between profitability of contractor and cost savings for operators. In this paper, an analysis for different cost models for IDS contracts that have been successfully implemented in one of the oil fields in Middle East by PETRONAS will be elaborated.

Three types of cost models have been incorporated by PETRONAS in one of the oil fields in Middle East for several IDS contracts during their tendering process. These cost models are lumpsum cost per well, lumpsum cost per meter and lumpsum cost per hole section. The wells were drilled to the same reservoir with identical well design and drilling operation sequences using rigs with same specifications in order to achieve fair comparison.

The awarded contracts with the three different cost models resulted in a range of well cost. Several advantages and disadvantages were observed during contract execution of each IDS contract implementing the different cost models. The lowest well cost in terms of IDS unit price was achieved by IDS contract utilizing lumpsum cost per hole section model. A cost reduction of up to 50 % was achieved compared to other IDS cost models. All the wells were drilled and delivered safely meeting the well objectives.

In some areas of Middle East, drilling operations are challenging due to constant security concerns which led to multiple operation suspensions, in addition to typical carbonate drilling challenges which resulted in higher drilling cost as compared to regional average. This paper would help the other oil field operators to utilize the IDS contracts with a proven and reliable cost model that ensures drilling the wells with lowest cost. PETRONAS has drilled more than 125 wells in one of the oil fields in Middle East utilizing various models of IDS contracts.
First Multilateral L4 Well with Six Open Hole Laterals in Middle East: Drilled and Stimulated All Laterals Under Challenging Reservoir Condition and Enhanced Production
Authors: Al-Otaibi Fahad Fares , Al-Awadhi Shareef , Ali Unneen Rijun , Dutta Abhijit
Published: October 2023

High level multilateral technology can access multiple reservoirs with lateral junction integrity, increase drain hole lengths that can result in enhanced production from a single location and significantly lower construction cost. It can also access conventionally unreachable reservoir thereby recover bypasses oils and enhance production objectives. This paper focusses on successful deployment of TAML 4 systems in Kuwait field providing independent accessibility of both laterals during life of well for cleaning, stimulation, zonal isolation, selective production, data acquisition, etc. It also details challenges faces while installing high level multilateral system, drilling six horizontals including three through multilateral junction and accessing both main bore and lateral. Paper details on completion designs, drilling challenges in complex reservoir structure and also discusses challenges of individually accessing all six open hole laterals successfully with advanced Coil Tubing System that allowed acid stimulation in each carbonate lateral and enhanced production.

The success of Multilateral Level 4 having six open hole horizontals comprising three in each of the two laterals that could be individually accessed through TAML 4 system and expected to produce significant amount of hydrocarbon trapped in formation with high degree of reservoir rock and fluid heterogeneity. The paper focuses on the challenges, solutions, and successful case study of the first Level 4 Multilateral having six open hole horizontals drilling in the Middle East. The paper also provides detailed workflow methodology for improving reliability of multilateral installations to maximize efficiencies. Successful acid stimulation using advanced Coil Tubing System that enabled selective entry into each of the laterals also enhanced production.

The successful application of TAML L4 would open new avenues of well construction that would enhance production at reduced cost and reduce surface location footprint in Kuwait fields.
Case Study on Catastrophic Failure of the Cooling Water Pump DE Bearing
Authors: Whittaker Simon , Sidhu Sanjit , Subramanian Moorthy
Published: October 2023

Case study on Catastrophic Failure of the Cooling Water Pump DE Bearing due to High vibration and Flow turbulence.

The Cooling water pumps are the core unit in the Gas separation plant for cooling the Condenser during gas separation process and these pumps are required in operation 24/7. This case study represents the Catastrophic Failure of the Cooling Water Pump DE Bearing assembly due to High vibration and Flow turbulence within 90 Days from the commissioning.

The function of a cooling system is to remove heat from processes or equipment. Heat removed from one medium is transferred to another medium, or process fluid. Most often, the cooling medium is water and the same get cool into ambient temperature when passes through the Cooling tower. In Oxygen gas production cooling water is circulated into the Surface condenser to remove the head during gas separation. High-capacity cooling water pump (6000 m3/hr.) plays an important role for continuous circulation of the cooling water in the closed loop.

During operation, a sudden increase in Pump B DE bearing temperature and immediately the pump tripped due to high current. During site inspection we found the DE Bearing housing was cracked and Pump rotor was shifted towards the Motor.

We have noticed the peaks at 1x, 7x & 14x in the FFT Spectrum along with Raising Floor noise which give the sign for the Flow turbulence/cavitation and VP Frequency.

Additionally, inspection on the Pump internals and other parameters was checked.DE bearing was completely damaged condition.DE Mechanical seal was also damaged condition.Found there was VPF and turbulence in the vibration spectrum.The Suction and Discharge piping was inspected, and suction isolation (Butterfly valve) position was shifted from Vertical to Horizontal for operator convenience.

Performed Butterfly Valve flow pattern using the software tool and found the most recommended pattern is vertical. Flow turbulence could occur if the Butterfly valve is in Horizontal position as this is Double suction pump.

The suction piping with necessary Valves and fittings needs to be designed & installed as per Pump OEM recommendation as it is important for the Pump to operate without any interruption. The Valve position is also very important and if any changes at site and the same required approval from the OEM.
Optimization of the Well Diagnostics Investigation
Authors: Yugay A. , Zhukin A. , Vorozhikhin S. , Girgis F. , Alkarbi M. A.
Published: October 2023

Well Integrity discipline is all about barriers. Double barrier envelope policy is a well integrity requirement well-known worldwide. This can be found in international standards: API RP90 (1 & 2), Norsok D10, ISO 16530 (1 & 2). This policy applies to wells with positive pressure at surface capable to flow naturally. Primary barrier envelope consists of well equipment which is in direct contact with produced or injected media. Secondary barrier envelope will be exposed to well media in case of primary barrier element failure. This paper focuses on such kind of wells that have a positive pressure at surface and fall under double barrier policy.

Any failure in primary barrier envelope (means - completion) is easily repairable during workover by simply re-completing the well with new completion. This can be done almost unlimited number of times, as long as there is a place to set the packer. Failure in secondary barrier envelope (means - casing) can be done as well, but not that easy and limited amount of time. In some cases, especially for onshore wells it might be economically more reasonable to drill the new well rather than to deal with complicated workover. Depending on the Company policy, casing integrity can be restored in sections using casing patches or the entire length can renewed by running and cementing casings of smaller diameter. Obviously, in both cases it impacts the size of the completion and cannot be done multiple times.
Wellbore Strengthening Geomechanics: An Engineering Design Workflow to Help Minimize Risk of Induced Lost Circulation
Authors: Savari Sharath , Van Beest Eric , Bonin Claudia , Guo Yonggui
Published: October 2023

Induced lost circulation in depleted sandstone formations is a risk in most deepwater drilling operations, often leading to costly operational delays involving remedial treatments. Wellbore strengthening (WBS) using lost circulation material (LCM) to plug an estimated fracture width is one approach to minimizing this risk of lost circulation. However, most simulations for estimating fracture widths are either numerical or linear elastic models that do not account for wellbore inclination, azimuth, and different stresses.

WBS planning involves fracture width estimation, which are kept propped open by LCMs. However, LCM blend selection is not often included in the wellbore strengthening workflow. In this work, a detailed field-friendly engineering workflow is presented that can estimate induced fracture widths accommodating wellbore inclination, azimuth, and different stresses around wellbore. The model also includes an LCM property referred to as "LCM blend stiffness," estimated using stress-strain data on different LCMs using a hydraulic press. The workflow accommodates varying LCM blends and, in turn, stiffness, to estimate maximum equivalent circulating density (ECD) providing wellbore wall and fracture-tip stability.

The estimated fracture width from geomechanics-based WBS engineering model was first compared with the existing linear elastic model under the same conditions and results were within 10% variation. Using inputs from a major operator in Gulf of Mexico under the same conditions, the estimated induced fracture width was approximately 70% wider with the geomechanics based model that included wellbore inclination, azimuth and stress anisotropy compared to the current simple linear elastic model. LCM blends with different stiffness values were used as inputs into the model, and maximum ECD gain was estimated that provided both wellbore wall and fracture-tip stability. The analyses will also highlight the limitation with the model for due consideration in the solution selection. A geomechanics-based wellbore strengthening workflow is presented, which uses an analytical solution to uniquely solve for stresses around the wellbore with fractures, and a methodology for balancing wellbore wall and fracture-tip stability.

The workflow aids in the selection of an optimal LCM combination that can provide maximum permissible ECD gain thereby stabilizing the wellbore wall (minimizing secondary fractures) and the fracture-tip (preventing fracture propagation). This is the first time that a geomechanics-based wellbore strengthening workflow accommodates LCM property and provides an estimation of fracture-tip stability.
Arthit Carbon Capture and Storage Project: The 1st CCS Implementation in Thailand
Authors: Kanokngam S. , Nitayaphan S. , Pulsawat M. , Sinthavarayan K. , Ngamlertsirichai N. , Nitipan T. , Rakpratanporn N.
Published: October 2023

Carbon Capture and Storage (CCS) is one of PTTEP's strategic pathways for the energy transition movement to become a low-carbon organization with sustainable growth and to achieve Net Zero Greenhouse Gas emissions within 2050 with an interim goal of a 30% reduction in GHG intensity by 2030. It will hence support a reduction in industrial and domestic emissions under Thailand's commitment at the United Nations Framework Convention on Climate Change (UNFCCC)'s 26th session of the Conference of the Parties (COP26) to reach carbon neutrality by 2050 and net zero greenhouse gas emissions in 2065.

CCS is the process of capturing carbon dioxide (CO2) from industrial sources before it releases to the atmosphere and permanently storing it in an underground geological formation. The sequestrated carbon will be properly managed and monitored for total safety.
Successful Application of Solvent to Treat Condensate Banking in High Pressure, High Temperature Deep Tight Gas Reservoirs
Authors: Al Hinai Adnan S. , Al Amri Ghusun A. , Al Subhi Salim K. , Al Kharusi Dawood N. , Al Yaarabi Ahmed M.
Published: October 2023

Condensate banking is a common challenge in tight gas reservoirs as it reduces the gas production rates. Solvent treatment is a temporary solution, it revives the well, but condensate will keep accumulating until the well quits again. The paper aims at presenting the best stimulation practices for condensate banking, examples from two high condensate gas ratio fields in the Sultanate of Oman. With the intentions of how solvent technology increased efficiency post-completion clean out and how shut-in wells were revived to produce more than 50m3/d of condensate with good sustainability.

The paper summarizes the status of the field prior to implementing solvent treatment & the main challenges in the field, from the well intervention & production perspective. It also illustrates the technical selection & success criteria utilized to achieve the objectives. In addition, a brief explanation on the lab testing that was conducted prior to injecting the solvent into the well.

It was observed that the crestal and western-flank wells are mainly affected by condensate banking (CB) and the impact varies depending on the petrophysical properties of the wells. While the eastern flank has scaling issues and suspected crossflow.

Tight sandstones reservoirs were deemed not suitable unless the initial stimulation technique was hydraulic proppant fracturing. The target was to achieve a productivity index improvement between 1.5-2 times for condensate blocked wells and a minimum sustainability of 6 months.

Laboratory trials were prepared on core samples from five different wells with three experimental approaches. One of the experiments showed inconclusive results. Condensate Emulsions were discovered for the first time. As an extra gain from the solvent system, was the possibility to degrade such emulsion at bottom hole conditions but further testing required to understand the technical reason.

A well that was closed for almost twelve months initially produced condensate three times the expected rate for four months and had dropped by half and has been sustainable. Depending on the well condition, bull-heading the solvent can yield the same results as that of coil tubing, saving a good amount of cash. In-house customized solvent recipe showed a 66% reduction in cost per well.

The paper will add information in the current reservoir stimulation techniques buy providing the lessons learnt to sustain gas production from challenging environments such as Sultanate of Oman's Fakhar tight gas field. Modelling condensate banking phenomenon in a dynamic reservoir model will improve our understanding of the challenge, and how we tackle it.
The First Implementation of Shifting Sleeves Using Real-Time Hybrid Coiled Tubing with a Flow Through 360° Multi-Side View Camera, Kuwait
Authors: Khandelwal Nakul , Chawla Sapna , Travesso Joshua , Al-Kreebani Mohammed
Published: October 2023

The ABC field in North Kuwait is a high-potential field that poses challenges regarding hydrocarbon flow assurance through tight carbonate intervals with uneven reservoir quality and curtailed mobility. These conditions have shifted the field development from vertical to Multistage Frac (MSF) horizontal completions to cover the maximum reservoir surface and economically produce hydrocarbons from the field. With an influx of water in some wells, intervention is needed to selectively shut sleeves reliably in candidate wells.

Candidate well XYZ is completed with a MSF horizontal completion and an Electrical Submersible Pump (ESP) with a Y-tool to provide access to the lower completion. Real-Time Hybrid Coiled Tubing (RTHCT) with a Modular Sensing Bottom Hole Assembly (MSBHA) has become the preferred intervention method to manipulate sleeves in horizontal wells. To further increase the intervention reliability in real-time, a flow-through 360° Multi-Side View Camera (360 MSVC) is added to BHA to confirm the sleeve's opening and closing and optimize intervention time and operational efficiency by reducing the number of Coiled Tubing (CT) runs. The 360 MSVC is composed of four high-definition cameras with adjustable lighting.

The unique solution provided in this paper confirms the benefits of customizing RTHCT along with the MSBHA and 360 MSVC to open and close shifting sleeves. This approach saved more than 30 hrs of intervention time for the operator, helped reduce cost, and put the well on early production. The entire job was performed in a single run using real-time data from the MSBHA and 360 MSVC transmitted through the RTHCT. The MSBHA provided critical, real-time depth accuracy using the Casing Collar Locator (CCL) and Gamma Ray (GR), differential pressure for tool activation, and accurate load/tension values while opening and closing sleeves. The 360 MSVC provided real-time vision and confirmed the opening and closing of three sleeves. The total time taken to confirm the opening and closing of sleeves was reduced to 30 mins using the 360 MSVC compared to 12 hrs using Distributed Temperature Sensing (DTS). This intervention approach increased operational efficiency by reducing operational time and therefore cost, while the real-time visualization from the 360 MSVC confirmed operational success.

This entire job was performed rigless, and the well was immediately put on production once CT was pulled from the well.

The 360 MSVC provided a real-time downhole insight to aid the decision-making process and help achieve the operation's success. The operator saved on rig costs compared to similar jobs in the past, and the same procedures and technology can now be applied for upcoming wells in this field or any other locations globally.
A JetSweep Technology for Cleaning Under-Pressured Wellbores
Authors: Ahmed Al Hinai , Ibrahim Kamyani , Fathiya Rajaibi , Ameera Al Harrasi , Talal Nahwi , Ghadeer Kalbani , Mohammed Nahwi
Published: October 2023

To present the "JetSweep Technology" which is successfully applied to clean out the sand-filled due to the presence of loss circulations and sub-hydrostatic pressures in the horizontal wells in the south Sultanate of Oman. It represents a significant improvement over conventional rig/hoist cleanout operations, it is the latest advancement in JetSweep technology.

Sand production is big challenge in PDO. During conventional tubing cleanouts, significant losses at the reservoir is encountered. As a result, conventional cleanout operations using hoist pumps would not be able to lift-up the sands from the well hence this could lead to the work string stuck, which costs PDO a lot to recover the situation. JetSweep Technology were able to control the flow rate during cleanout and minimize losses, this helps to carry the sands from the well to surface. The major portion of the flow rate powers the jet sweep, which drives suction force, while the minor portion sweeps up the well by bypassing the isolation packer and driving fluid and sand to the surface while maintaining balanced pressure conditions. JetSweep Technology is able to clean wells from sand to the desired depths to un-plug the perforations for production restoration. This results on prolonging the performance of the production pump. Moreover, few interventions required over the well's lifecycle. Also, increases the well life cycle time, reduces replacement pump expenditures and deferments.

With JetSweep managed to shut off the water producing zone after cleaning and maximized the oil production. PDO successfully cleaned more than 210 wells and reduced oil deferment by US$16.38mln/year.

Additionally, before JetSweep, the wells used to be cleaned using Coil-Tubing Unit which is normally done between two mandatory hoist entries (preparing well for CTU and completing well). These activities now are substituted by single hoist entry in one-go using the JetSweep, this has resulted into additional saving of US$ 1.5 million per year subsequentially.

In summary, by using JetSweep, managed to:

Reduced cleanout operation times and pumped fluid volumes. Achieve full well bore oil production. Retrofitting wells with new wire-wrapped screens for sandy wells. Retrofitting with AICD/AICV to reduce water cuts.

Going forward, all wells with expected losses, JetSweep technology will be used with different applications:

Sand/Scale cleanout. Stimulation Acid lift-up. Post-Frac sand cleanout.

JetSweep technology is now seen as standard way of cleaning such wells from sand with losses during the clean-out. In PDO, it constitutes a game changer that is reducing the well life cycle costs, deferment and HSE exposure.

The global industry, where such challenges are present, PDO experience and learning would definitely help replicating the use of this technology to improve the efficiency of operating the wells during the depletion phases.
First Onshore DAS VSP in Abu Dhabi, A Complete Case Study, Onshore Abu Dhabi, UAE
Authors: Vargas Jose , Ofowena Frank , Ahmed Jahan , Bailey James
Published: October 2023

ADNOC Onshore tested the distributed acoustic sensing (DAS) Vertical Seismic Profile (VSP) technique in a well in an Onshore field in order to gain confidence and knowledge for future commercial DAS VSP applications. The main VSP objective was to assess data quality for VSP imaging and velocity information. The VSP test ran prior to an injection startup test, allowing the effect of injection noise on active VSP records to be studied. A walkaway (multi-offset) VSP design and Zero-Offset VSP were selected. The operation required good communication within a diverse discipline project team. The VSP operation was under constant assessment throughout. A daily QC process was executed as planned: enabling field data to be checked, to ensure quality and confirm operation decisions. One of the main project risks was the uncertainty of data quality concerning fiber coupling to formations. In this case the fiber was deployed behind the tubing, and prior examination of casing cement bond logs showed fiber coupling to formations was not guaranteed over the full length of the well.
CO2 Injectivity Test Proves the Concept of CCUS Field Development
Authors: Kaipov Y. , Theuveny B. , Maurya A. , Alawagi A.
Published: October 2023

The paper presents a unique case study on injectivity tests done in the Kingdom of Saudi Arabia to prove the concept of Carbon Capture, Utilization, and Sequestration (CCUS) capability. It describes the design of surface and downhole testing systems, lessons learned, and recommendations.

The energy company drilled appraisal wells to evaluate the multi-zone reservoirs with saline aquifers. The objectives of the injectivity test were to confirm the seal integrity (initial wells), reservoir injectivity, and surface injection pressure. The injectivity tests included the injection of water, N2, and CO2 at different regimes followed by fall-off after each phase. The Surface Testing System was used to pump and control the flow and measure the injection pressure and temperature. The Downhole Testing System is represented either by Monobore completion or DST where the downhole pressure and temperature measurements with wireless real-time telemetry are done at different depths.

The injectivity test brought great value in identifying and confirming the best reservoir for CO2 injection and defining the best completion strategy. Creating the injection conditions close to CCUS is vital, especially in heterogeneous carbonate reservoirs where the petrophysical correlations for the reservoir model require calibration with dynamic data.

The initial campaign consists of injecting the water up to frac pressure to confirm the seal integrity. Then, the water and N2 injection tests were done to determine the reservoir injectivity with different phases. These tests included injectivity profiling to evaluate the vertical heterogeneity. After an initial assessment of reservoir injectivity and selecting the reservoir for CCUS CO2 injection tests were conducted.

The CO2 injectivity test was challenged by the limited volume of CO2 tanks, its corrosive nature, and very low temperature. The surface and downhole system had to withstand these conditions and also the test duration should be optimized to get the representative pressure transient response for the available volume of CO2.

The downhole gauges provided the data for pressure transient interpretation during injection and fall-off periods. The real-time monitoring allowed us to interpret in real-time and optimize the test duration. The combining of multiple gauges at different depths allowed us to evaluate the friction losses in completion during high-rate injection and CO2 phase changes during the fall-off due heating effect. The CO2 injection creates an extreme cooling inside the well and this affected the downhole gauge behavior at certain conditions.

For the first time, the injectivity test with CO2 was completed at the appraisal well. Authors will provide the unique workflow, lessons learned and recommendations to the industry based on more than 10 wells with 4-6 individual injectivity tests.