bluuebunny/crossref_metadata_2025_split huggingface dataset:
Improve Completion Decisions with Enhanced Dynamic Reservoir Modelling and Effective Reservoir Management While Drilling: Integrating Downhole Petrophysics with Advanced Surface Mud Gas Logging (AMGL) Techniques
Authors: Fernandes A. K. , Gligorijevic A. , Khanal G. , Botelho S. , Dekker R. , Chua C. , Lai J. , Hairi H. , Lim K. , Dieckmann V. 
Published: February 2024

Abstract
In a brownfield, it is common to observe the movement of fluid contacts and alterations in petrophysical behaviors resulting from production and injection activities. The acquisition of field surveillance information through well intervention in a deep-water field with subsea wells is limited as it comes with a significant cost and poses a substantial risk to the asset. Furthermore, burdened by limitations in gas handling facilities and challenges associated with water emulsions, the primary objective for new infill wells is to achieve the minimum feasible gas-oil ratio (GOR) and water cut. Thus, innovative data acquisition while drilling infill wells, such as strategically penetrating shallower producing reservoirs close to the anticipated fluid contacts without risking the primary well objective, is required to de-risk uncertainties.
Advanced mud gas logging (AMGL) has been and remains to be a reliable surface measurement to log and determine downhole fluid composition. New workflows using AMGL, combining extraction efficiency calibrations before drilling with mud gas isotope logging (MGIL), enable an improved, consolidated application for real-time insight to the fluid properties.
This paper presents the use of reliable geochemical signatures together with downhole petrophysical interpretation while drilling in a mature oilfield, leading to more effective reservoir management. Continuous fluid properties from AMGL coupled with MGIL and integration with logging while drilling (LWD) measurements allowed to timely assure the existing dynamic reservoir model and subsequently optimize well completion, steering production towards zones with low GOR and low water cut. Specific mud gas ratios utilized to qualify water intervals and identify fluid type aided landing decisions also when LWD information was not available. In addition, AMGL was able to identify the fluid composition, with high certainty, from tight rock intervals. The gas cap formed due to gas expansion and gas injection was also identified by combination of AMGL and MGIL measurements result.
Establishing a numerical model from laboratory, derived from pressure-volume-temperature (PVT) analysis of a downhole fluid, then implementation of these cut offs on AMGL data while drilling, highlighted a potential for being implemented as an industry standard for effective reservoir management.
Real-time AMGL and petrophysical information were combined to enable an integrated and holistic view of the reservoir and fluid fills.
Accelerating Cement Set for Surface Conductor in Deepwater Environment
Authors: Elder M. , Horn T. , Jordan C. , Amer W. , Gohel C. , Conil L. , Shand S. 
Published: February 2024

Abstract
The objective of this paper is to present the pre job planning, modelling and results of an IOC first deployment of a post cement job hydration accelerating heat sweep. This heat sweep utilizes a pit of pre heated seawater which is circulated into the casing on completion of the conductor primary cement job, to accelerate the early compressive strength development of the cement. This rapid cement hydration technique is enabled through a mechanical stabbed in cementing system that optimizes the placement of the conductor primary cement job and eliminates conventional cement or sub surface release (SSR) plug shoetracks.
Preparation for the job involved the service company utilizing a heat transfer software to simulate the heat transfer from the seawater through the casing and into the cement column. This heart transfer modelling was then utilized to create a temperature profile of the incremental temperature increase of the cement and corresponding effect on early compressive strength development. In addition to this, the third party cementing company conducted an ultrasonic cement analyzer (UCA) test to further model the influence the heat sweep would have on the compressive strength development of the cement based on the heat transfer software simulations.
The conductor cement job was completed successfully, with the stabbed in inner string cementing system and post cement job heat sweep saving the operator rig time. The conductor cement job was completed in a water depth of 344m, with the 30" conductor shoe set 87m below mudline.
Post job data was obtained through a downhole temperature logger located within the stabbed in inner string cementing system. This logger provided memory data from the run in hole (RIH), pre job circulation, pumping of cement job and circulation of a heat sweep with a temperature of 70 degC at surface. The temperature logger recorded a downhole temperature of 61.2 degC 4m from the float shoe.
Both the stabbed in inner string cementing system and rapid cement hydration technology have the potential to reduce rig time and mitigate against various operational risks in the global deepwater well construction space.
Water Flood Segment Review Processes and Utilizing the Voidage Replacement Ratios & Efficiency Indices to Rationalize the Management of Water Floods in North Kuwait
Authors: Al-Otaibi Sabah , Akhter Shamima , Al-Otaibi Yousef , Chetri Hom 
Published: February 2024

Abstract
One of the performance indicators for the assessment of the ongoing water floods is the concept of Voidage Replacement Ratio (VRR). Often, it has been experienced that the VRR numbers are either used or abused during the waterflood management leading to inconsistent decisions. Coupled with the water injection efficiency, VRR becomes a powerful tool to manage mega size water flood in Kuwait. The paper is an attempt to examine various sources of errors in reporting VRRs and suggest a deep-dive approach, rather than simplistic methodology.
Amongst the portfolio of reservoirs under active water flood in Kuwait, there are reservoirs with purely depletion drive mechanism operative while others have some degree of aquifer support. Another category comprises those reservoirs where injected water quickly re-circulates to the nearby producers. There are segments & compartments within the same reservoir. Detailed & comprehensive review is done to have the sub surface understanding by due integration of all data. Once the physics of flow of injected water is known, the VRR computation is performed using databased artificial intelligence, instead of simplistic way of volume-to-volume ratio with a single number for each reservoir. The Water flood segment reviews and diagnostics require to be utilized for scaling the VRR for each segment or block of the reservoir. Water injection efficiency computations help for rationalizing quick decisions.
Various kinds of VRRs are computed such as instantaneous VRRs, Cumulative VRRs, VRRs for areas below Bubble point pressure, VRRs for active segments/ patterns, VRRs in pure depletion mode, VRRs under aquifer support scenario and VRRs with quick re-circulation/ thief zones. Once all of these values are known, pattern/ segment or field management is done in accordance with the reservoir requirements to scale the allowable and re-distribute the injected water for maximum benefit. Water flood optimization in Sabiriyah Mauddud (SAMA) result in 10% reduction of re-circulation water and generated stable water cut performance during last 2 years. In addition, the VRRs could address the reservoir heterogeneity and connectivity to some extent helping the team to take prudent decisions to plan activities for improving water injection efficiency. The chances of over-injection or under-injection are avoided for all areas of SAMA. Various visualization tools using OFM & Spotfire helps in decision making under collaborative platform.
A powerful option to incorporate performance based VRRs & water injection efficiency with a rigorous approach helped the team to utilize the water injection resources smartly.
Navigating Complexity: Success Stories of Decommissioning a Lightweight Marginal Field Platform
Authors: Yee Teh See , Shaharuddin Noor Hidayah , Yuan Shu Shik , Zainai Ts. Ariff Irfan , Samsu Julina 
Published: February 2024

Abstract
As global oil and gas reserves continue to deplete, and aging platforms near the end of their design and production life, the imperative for their removal, commonly referred to as decommissioning, becomes increasingly pronounced. This paper sheds light on a recent offshore decommissioning project in Malaysia, concluded in June 2023, which distinguishes itself through the pioneering reuse and refurbishment of the decommissioned topside for a new oil and gas development project by a different operator. Simultaneously, the substructures underwent complete removal from the site for onshore disposal.
The decommissioned platform, a three-legged conductor-supported structure installed by a jack-up rig, presented unique challenges in its removal. Located just 3.3 nautical miles (approximately 6.1 km) off the coast of Sarawak, Malaysia, the soft soil conditions rendered jack-up rig removal too risky, a lesson learned painfully during the initial platform installation. The shallow water depth of 10 meters MSL further constrained lifting vessel selection and associated marine spread, posing challenges in planning well plug and abandonment (P&A) activities and overall facilities removal. Additionally, the decommissioning methodologies for this ‘conductor-supported platform’ significantly deviated from those typical of wellhead platforms.
This paper provides a comprehensive account of the decommissioning process, addressing challenges across all phases, including well abandonment, pre-abandonment surveys, data gathering, engineering, decommissioning, structural removal and transfer, disposal, and final site clearance. The successful execution hinged on critical factors such as engineering studies, cutting tool selection, removal sequences, and vessel selections.
Beyond the technical hurdles, the paper explores the collaborative efforts of the Project Management Team and Malaysia's regulatory body in optimizing schedule and costs. It aims to engage and inform those interested in platform and facilities abandonment and decommissioning, guiding readers through the entire journey of platform facilities decommissioning and removal.
Development and Successful Field Application of a Novel Low Solids, Brine-Based, HTHP Well Testing Fluid
Authors: Mudgal Punit , Dhavle Mayuresh , Lavale Vaishali , Navarro Raul , Khati Milind , Jadwani H. , Zhou Hui 
Published: February 2024

Abstract
Deep and ultradeep reservoirs are commonly characterized by high temperature and high pressure (HTHP), which poses a severe challenge to well testing operations. The requirement for high-density clear brine drives the overall cost of the well testing operations. There are only a few alternative high-density (&gt;14.5ppg) clear brines in the market that can deliver the hydrostatic pressure requirements for HTHP wells. Zinc-based brines pose health, safety and environment (HSE) concerns, and can show high general corrosion rates as well as issues with elastomer compatibility. There are other alternative high density brine systems that are more benign, but they may have limits with respect to density and crystallization temperature, and/or they may have an extremely high cost per barrel. Considering the challenges of minimizing HSE risks and costs, a high-temperature divalent brine-based completion fluid was designed, utilizing novel synthetic polymer technology. This paper presents the laboratory work and field performance of this newly developed low-solids, brine-based, clay-free fluid system designed for HTHP well testing.
14.2ppg calcium bromide (CaBr2) brine was selected as the base fluid to provide density and minimize the total amount of acid-soluble solids in the fluids (as well as a very low crystallization temperature). Lab studies were conducted for rheological stability across a range of temperatures and for long-term stability under high temperature conditions. Return permeability tests were conducted on the final formulations to validate their suitability for use in the reservoir. The synthetic polymer technology provided excellent rheology and suspension in the fluid systems designed in the laboratory and proven in the field applications.
The fluid was re-utilized multiple times in multiple wells and adjusted as per well requirement of density to control downhole pressure. This reusable well testing fluid resulted in a significant cost reduction to the operator.
Renewable Local Power to Decarbonise Offshore Energy
Authors: Ferreira J. S. , Lewis M. , Silva A. , Crossland I. , Slorach P. , Money N. 
Published: February 2024

Abstract
Momentum is building within the global offshore oil and gas industry to reduce carbon emissions in line with net zero targets and industry agreements around decarbonization such as the North Sea Transition Deal in the UK. As part of this drive to reduce emissions and to decrease reliance on traditional sources of power, integration of renewables within offshore operations is increasingly being seen as a viable solution.
In order to encourage wider adoption of renewables within these operations, successful projects must be demonstrated to show the viability of renewables in this environment, as well as the capability of overcoming the intermittency challenges associated with renewables.
The Renewables for Subsea Power (RSP) project, launched in 2020, is said to be a first-of-a-kind commercial scale demonstrator project which provides a fully integrated offshore power and over-the-horizon communications solution through the integration of a wave energy device and a subsea battery energy storage system. The project demonstrates power export to the subsea energy management system, powering both subsea controls equipment and underwater vehicles through a remote wireless communication link to the subsea equipment.
In this paper, the focus will be on the development and progress within the RSP project. Discussion will include observations from Phase 2 onshore commissioning, as well as the offshore demonstration which began in February 2023 in the UK North Sea and has been operational over a nine-month period.
Beyond innovation in the developed hardware, the project provides a case study of a wider industry collaborative approach, addressing the need to explore ways of achieving a net zero future and work towards enhanced energy security, including for offshore operations. The project is relevant to numerous remote power provision applications across the ever-growing Blue Economy.
Scale Inhibitor Dosage In Seawater Injection: Insights Into Long Term Advantages Of Continuous Dosage and Implications Of Inadequate Dosage
Authors: Uniyal R. , Devshali S. 
Published: February 2024

Abstract
This paper aims to elucidate the various benefits of continuous dosage of suitable scale inhibitor into the reservoir through injection water to prevent down hole deposition of scale in offshore development wells. Various consequences of inadequate chemical dosing have been deliberated. Detailed description of methodology adopted for chemical selection has also been elaborated in the paper.
Most oilfields in India's Western Offshore region are brown/matured fields which have been in production for more than three decades. Reservoir pressure management system, which includes seawater injection as one of the primary techniques, has been in place since the 1990s. Seawater has a high concentration of inorganic minerals which are not always compatible with formation water. The chemical injection plan, part of the larger seawater injection system, had initially included provision for anti-scalant injection. The same was however discontinued at a later stage based on a separate study. The study took into account the water chemistry at the time (late 1990s) and stated that the water was unlikely to scale in the near future. Two decades on and inorganic scaling has plagued majority of the development wells in the field. This has led to a rampant rise in the requirement of scale removal jobs in the field over the past decade or so. Scale prevention is a superior and economical alternative to scale removal due to reduced consumption of chemicals and prolonged life. As part of this study, the feasibility of continuous injection of a suitable scale inhibitor into the reservoir has been re-examined and subsequently, extensive laboratory experiments were performed to identify suitable chemicals. Additionally, the repercussions of not dosing a suitable chemical/ inadequate dosage have been discussed.
As part of the study, injection water samples were collected from strategic locations all over the western offshore injection water network and analysed for scaling tendencies. The results show beyond doubt that decades of production has led to injection water breakthrough/encroachment and with it, the problem of inorganic scaling. Based on a comprehensive literature review and market scouting, six inhibitors were evaluated for their inhibition efficiency, thermal stability and compatibility with the rock formation through laboratory experiments under simulated reservoir conditions. Based on the results, chemical X was identified as being most suitable for continuous injection into the reservoir to combat scaling issues in both injection and development wells.
The study discusses the various pros and cons of continuous scale inhibitor dosing thru seawater injection for an offshore carbonate reservoir. It analyses the feasibility of starting afresh a scale inhibitor injection program, after the field has been in production for more than 3 decades. The entire chemical selection process has also been detailed.
Complex Multi-Stacked Reservoir Development – A Successful Case Study Offshore Gulf of Thailand
Authors: Limniyakul T. , Wasanapradit T. , Chigbo I. , Khunmek T. , Yew Z. , Tan C. , Moses N. , Ornman P. 
Published: February 2024

Abstract
Many fields in the Gulf of Thailand (GoT) consist of multi-stacked reservoirs with various degrees of aquifer strengths and varying reservoir properties. Commingled production with sand control has been challenging due to productivity loss from sand failure, and/or early water breakthrough. This case study demonstrates how a combination of integrated reservoir simulation and out-of-the-box well completion designs were used to enhance recovery and economically develop an otherwise marginal 1500 ft. long small multi-stacked reservoir offshore GoT.
Separate static and dynamic models existed for two of the four reservoirs of interest. A pre-drill study amalgamated the static models into a single stacked model in readiness for a multizone commingled flow study. A high-resolution numerical simulation model was then created, integrating varying rock properties and aquifer strengths observed from historical data. The completion strategy sought to isolate multiple water bearing zones straddling the hydrocarbon zones with swell packers and integrate inflow control to manage the variability in reservoir properties and aquifer sizes. A real-time update of the pre-drill model was required to best optimize the inflow control device (ICD) design.
During the campaign, multiple additional oil-bearing reservoirs were discovered. The team quickly updated the geological models and generated fit-for-purpose high resolution dynamic simulation models, building in multiple scenarios with more than a million active grid cells, to best reflect the understanding of the new reservoirs. This was done within the very short time permitted by operational constraints and helped increase the confidence in ICD nozzle sizing. The reservoir drilling fluids had to be modified to ensure a good swell packer performance for zonal isolation integrity. A total of 8 sands were completed in this well, from 4 originally planned. Post-drill production performance from the well suggests a strong conformance to the pre-drill models as far as inflow goes. The benefit of the ICD deployed in this highly deviated well was demonstrated, with the smaller nozzle sizes limiting inflow from zones with higher productivities and quicker water breakthroughs. The swell packers performed very well judging from the water cut profile from the well. A similar approach is planned to be used in multiple other marginal multi-stacked oil reservoir in this field and others.
This study demonstrates what is possible when different areas of expertise work together to combine/integrate multiple separate existing technologies. High resolution numerical simulation was combined with sand control and inflow control technologies with modified drilling fluids and swell packer designs to make the development of these otherwise uneconomic multi-stacked marginal reservoirs possible.
A Case Study on Extracting Insights from the Initial Implementation of Liner While Drilling Technology in the Western Offshore Region of India
Authors: Bagga Pawandeep , Pethe Sarang , Bhelonde Rajan , Pandey V. K , Gupta Rakesh , Gupta Arpit 
Published: February 2024

Abstract

Objectives/Scope
The Mumbai High field located in the Western offshore of India poses significant challenges for drilling and liner running operations due to reservoir depletion and severe lost circulation conditions. As a result, a pilot project was implemented to address these difficult carbonate reservoirs using a new technology called Liner while Drilling. The operator had previously encountered substantial losses in the zone, resulting in significant rig downtime and damage to the reservoir caused using Loss Circulation Materials (LCM) Pills.

Methods, Procedures, Process
To overcome these challenges, the Steerable Drilling Liner service was employed, which combines a rotary steerable system and Logging while drilling tools with a liner. This innovative approach helps in drilling through zones with lower pressure and unstable shale/coal layers, as well as formations with varying flow and pressure conditions. The integrated Bottom hole Assembly includes an Underreamer to enlarge the drilled hole, enabling the liner to cover the open hole portion during the drilling process. It is worth noting that drilling with a mud motor and low RPM from the surface puts less stress on the formation compared to conventional Rotary Steerable Bottom Hole Assembly (BHA). In the second run, cementing is performed with the assistance of a cement retainer assembly. Finally, in the last run, a Completion Packer and Liner Hanger are set to hand over the well to the operator.

Results, Observations, Conclusions
The use of special mud additives and Liner while Drilling technology effectively contained losses. The plastering and smearing effect across the wellbore provided value in addressing the losses. This technology reduced formation damage by eliminating the need for repeated LCM pills. The Steerable Drilling Liner service helps mitigate the risks of hole collapse and formation damage by reducing exposure of the open hole section, minimizing non-productive time (NPT) by eliminating extra trips, and ensuring that the liner is installed at total depth (TD) during the first run.

Novel/Additive Information
This paper will provide a detailed discussion on the application of Liner while Drilling technology in the Indian Western Offshore Field. It will cover lessons learned from two deployments, opportunities for improvement, and the way forward. Additionally, the paper will examine the execution of the technology in two specific wells, addressing the challenges associated with each well and the methodologies employed to overcome them.