bluuebunny/crossref_metadata_2025 huggingface dataset:
Optimization of Pipeline Welding Qualification, Production and Effective Field Joint Coating Application
Authors: bin Ahamad Ir. Edment Fashah , Ong Ir. Hock Guan
Published: March 2022

Over the years, offshore underwater pipelaying has been regarded as complex activities ranging from procurement, manufacturing of mother pipe material, welding procedures, and welders qualification until offshore installation at the lay barge. Each project has different complexities subject to the appointed pipelines installation contractor depending on their preference methods and best practices. This article presents how continuous improvements are being made in recent pipeline installation projects by considering the benefits that were learned from all past project's experiences. Multiple simplifications were conducted recently to gain cost and time reduction while maintaining technical integrity and personal safety requirements. Simplification of WPQT and WQT qualifications with minimum welding test coupons preparation had resulted in significant cost avoidance and reduction of a 66 days from the original plan. The new deployment of the innovative FJC system has significantly improved personnel safety, reduced manpower requirement and resulted in faster application. Few strategies were put in place to minimize the welding repairs and allow concurrent activities to speed up the offshore welding progress. The overall improvement for one of the recent pipelay activities has led to the highest pipelay rate in SMEP with record of – 337 jts/day (10") & 256 jts/day (16") over the campaign and achieved 16 days early completion from the original pipelay campaign schedule.
Implementation of Key Risk Mitigation Strategies and Learnings Enabling Successful Efficient Execution in Malikai Phase 2 Project Mooring Campaigns
Authors: Amurol Jamal Sharizal bin , Hii Tiing-Poh , Ang Zhili , Yip Kenneth , Lim Tee Bin
Published: March 2022

Malikai Tension Leg Platform (TLP) being the first TLP in Malaysian waters, was installed in 2016 at a water depth of 500m. The mooring system was designed with tender-assisted drilling (TAD) features to allow for station keeping activities during drilling operations. Malikai Phase 2 is brownfield project to develop six infill wells to be drill using existing well slots available on TLP. To drive project value of replication and standardization, similar TAD vessel was used as per Phase 1 campaign.

The project execution strategy emphasizes on the reuse of Phase 1 mooring component to lower the CAPEX and re-certification of the mooring component were done to maintain the integrity of the hardware. Existence of porkmarks and large part of geo-hazard on the Malikai seafloor, remain one of the main challenges to safety pre-lay polyester on the selected routes. Furthermore, due to Covid-19 pandemic the shipment of the polyester ropes was delayed. Improvement was made in the offshore installation methodology with introduction of the direct hook-up methods to eliminate the risk of polyester damaging during pre-laid, eliminate the chain twists issue on ground chain section and that also help in preserving project schedule. The development of innovative contracting and supply chain management strategies such as competitive bidding exercise and leverage on contractor expertise to drive the efficient execution. Virtual working setting is a new way of working in marine assurances due to Covid-19 travel restrictions.

This paper will provide a board overview of various aspects of Malikai Phase 2 brownfield development during pandemic condition while highlighting key success factors and lesson learned for future projects.
Biggest Wells Plug and Abandonment Campaign – Effective Management & Best Practices Implementation
Authors: Azihar Azwan Azim , Abu Mukhtar Maziah , Yang Shahril , A Razak M Zahin , A Rajab A Zawawi , Tumiran M Azlan
Published: March 2022

This paper covers the strategy that led to successful execution of Plug and Abandonment (P&A) campaign. This paper also shares the best practices implementation, and challenges in completion of the biggest plug and abandonment campaign at Alpha Platform in Peninsular Malaysia. Among the challenges are aging wells with numerous integrity issues, well sequence selection and prioritization, monsoon season, stakeholder management as well as piloting new technology applications.

In the last 5 years, there are over 50 wells have been successfully abandoned in Malaysia water. The generic abandonment project management framework consists of Initiation Stage, Concept Selection, Scope Definition, Execution, and Post Execution; Close Out. The scope for this paper will detail out the levels for abandonment planning. Screening and clustering, fit-for-purpose strategy, novel technology, innovative contracting strategy are among the pillars in abandonment planning and execution. Effective tools and matrix have been introduced to evaluate the wells candidates. Execution phase is narrowed down to several approaches and best practices that have been implemented to successfully complete all wells at Alpha Platform. The approaches have been customized to safely abandon wells with sustained annulus pressure (SAP) in compliance with the country's regulations. In-depth well study and aggressively piloting new technology are among the keys to tackle numerous well integrity issue in 40 years old wells e.g shallow gas, casing leak, wellhead, and Christmas tree leak. Vigilant logistic management and integrated contract approach also play important roles in reducing the risk and liability to the operator and at the same time developing local players’ capability.

The strategy and best practices in completing plug and abandonment of Alpha Platform should be replicated by P&A industry to manage the similar issue in other projects. Integrated and fit-for-purpose abandonment approach act as the foundation to model invaluable high-quality planning, forecasting and Value Creation Plan for P&A project portfolio. This paper will be useful in P&A industry where a lot of lessons learned to be shared in the biggest campaign in Malaysia.
Applying Downhole Sand Control for High Rate Gas Completions in Deepwater Malaysia
Authors: Samuel Elvy Jose , Yusoff Mohd Faizal , Bee Phil , Hakam Ahmad , Selamat Kasim , Stevenson James , Nopsiri Noppanan
Published: March 2022

Designing and delivering a successful completion in a Subsea High Rate Gas Deepwater environment is known to be one of the most challenging aspects of a Field Development.

For the specific case of high rate gas wells with reservoirs requiring sand control, it makes the completion reliability and longevity an uncompromising prerequisite, as it is well known that formation solids moving at high velocity through the wellbore can drastically affect the functionality and integrity of downhole equipment as well as the subsurface and production facilities. In addition, to the previously mentioned aspects, the complexities and costs associated with Well reentries and Workovers in a Subsea Deepwater environment can quickly erode the overall financial viability of a development program.

This paper covers the sand control design and execution techniques applied to four (4) High Rate Gas Wells in the PTTEP's Block H Development in the Malaysian Deepwater region of Sabah, between 2020 and 2021.
Single Trip Sand Control and Cementing System
Authors: Moses Nicholas , Ismayilov Elnur , Newn Edwin , Mogga Emmanuel , Zou ChunLei , Poizat Jeremie , Milne Gordon , Sanni Ireti , Thomson Stewart , Haubrich Blayne
Published: March 2022

The operator of field S initiated a project with a key objective to unlock and increase oil recovery while maximizing the economical oil ultimate recovery and maintaining a daily production with a ceiling unit development cost. The targeted sandstone reservoirs are shallow with unconsolidated formation which require active sand control. To achieve the objectives, a Single Trip Sand Control and Cementing System was developed by the service provider utilizing existing proven technology which was adapted to be a fit for purpose solution. The main driver in developing the single trip system was operational simplicity. The high-level procedure of the system is:

Drill open hole from surface to target depth in a single run. Make up lower completion assembly and production casing and run to target depth. In the same trip, set production packer and release service string. Gravel pack the lower completion or install as a stand-alone screens completion and cement the production casing in place before pulling out of hole.

Once the single trip system was designed and developed, a detailed system integration testing was carried out to ensure that the technology performed as expected. The turnaround time from design to execution was reduced tremendously by utilizing existing proven technology with minimal modification required. From there, 2 wells were identified for a pilot technology trial where this novel system was implemented. The execution of these 2 wells was successful with the expected learning curve of implementing a new system. One of the key findings were the robustness of the system as it was applied in a well with higher than normal doglegs, highly deviated shallow reservoir and the sand screens were run through extended open hole shale sections which would have been cased off in a conventional completion approach. Additionally, the single trip approach allows for further optimization with multi-skilling personnel, and this led to an improved operational efficiency. Post well completion, the 2 wells have been successfully put on production and are producing sand free. This unconventional approach can unlock more marginal reserves that were previously not feasible to be developed economically.
Newly-Developed Visualized Reservoir Characterization While Drilling Technology Improves Understanding of Complex Channel Sand, Assists EOR in a Mature Oilfield in Bo Hai Bay
Authors: Yang Bin , Nie Min Chao , Shen Hong , Li Yu Guo , Xu Nian Da , Zhang Hua Guo , Niu Cheng De
Published: March 2022

PLxx oilfield is a mature oilfield which has been developed by horizontal wells for several years with water-injection production style. It features with shallow, complex, high challenging unconsolidated channel sand with lateral property variation due to pinch out, stacking or lamination. The thickness of pay zone changes from couple of to ten more meters which brings much high challenge to reservoir delineation while drilling and horizontal well placement execution. The oilfield locates at a faulted belt of Bo Hai Bay among which some small faults may happen. But it's difficult to be identified because of the low S/N ratio incurs from the shallow gas effect on the seismic data.

Moreover, uneven flowing zone units exist within sandstone package due to dynamic reservoir production, uncertainty of lateral sand connections and possible inter-well interventions. As such, this makes the oil-water distribution more complicated and the oil-water contact isn't uniform in the sand package.

In order to furtherly understand the complex channel sand, place the wellbore in the favorable sweet spot and enhance the oil recovery, a newly-developed visualized reservoir characterization while drilling integrated technology associated with RSS(rotary steerable system), HSVP(high speed data transmission system), RTC(remote transmission connection through Internet) and OSC(operation support center) was employed to optimize the operation efficiency during a three-wells drilling campaign in this oilfield. This newly-developed reservoir characterization technique is the industry innovative fully 9 components measuring azimuthal Electro-Magnetic propagation tool in one single sub. It provides not only the conventional propagation resistivity but also the geo-signal responses in a very quick, flexible way. In one of the case, the unique "Dual-diagonal orthogonal T-R antenna design" ensures the DOI (depth of investigation) as deep as 6.8meters.

The reservoir boundaries such as the top, the bottom or the oil-water contact were distinctly characterized and the horizontal drainage section was precisely navigated within the profitable pay zone. The post-well reservoir characterization result is comparable with the seismic profile and very helpful to understand the dynamic reservoir flowing zone unit. The excellent performance is also reflected in the oil production; the initial oil production was increased from 40 m3/day to 69m3/day which is 75% higher than expected. Minimum 25% of oil recovery will be enhanced as forecast.
Understanding the Impact of Corrosion on Gas Wells Past its Design Life
Authors: Zaidil Hanani , Wong Sim Siong
Published: March 2022

Field X produces dry gas from a carbonate reservoir with moderate aquifer support consisting of 16 wells most of which were drilled between 1986 to 1987. Up until 2021, these wells would have been in service for approximately 35 years, past its theoretical design life. Based on production forecast, the field is expected to continue producing for another 10 to 18 years. In view of the prolonged life extension, there is a need to review the integrity status of the well to ensure safe production until the end of field life. Wellhead preventive maintenance are conducted on a six-monthly basis to assure safety critical equipment (SCE) functionality and performance. Maintenance data collected since 2008 provides a good view on surface and subsurface valve integrity.

In recent years, observations on external corrosion have received some attention. At the same time, there were efforts in determining and verifying the corrosion rates for production tubing, wellhead and x-mas tree. For well tubing and production casing, load based assumptions were used to estimate the minimum allowable tubular thickness to establish a basis for remaining life estimates. To verify the remaining life estimates, in 2019, a multi-finger caliper log was ran across the tubing of Well B to measure actual metal loss around the pipe. A magnetic log was also run in Well B in the same year to obtain quantitative measurement of remaining metal thickness in 13-3/8", 9-5/8" and 7" tubing. The observations from these exercises indicate that calculated estimates are more conservative as they do not account for the impact of the highly dynamic conditions downhole. While logging provided an independent view of the condition of the tubing and casing, no inspection of the x-mas tree cavity was carried out. An opportunity to close this gap and obtain information on the internal condition of the x-mas tree body is presented to Field X with the abandonment campaign on two idle wells in quarter three of 2021. The x-mas tree was retrieved, and internal inspection was conducted. The same is done for retrieved tubing from the abandoned wells.

This study and its findings will enhance understanding on well design life, especially for vintage wells of over 30 years and provide assurance that wells are safe to produce.
Safety Control Technology of Ultra-High Pressure Gas Wells with Annular Pressure: Case Study of Tarim Oilfield
Authors: Cao Lihu , Sun JinSheng , Zhang Bo
Published: March 2022

Kuqa foreland basin in Tarim Oilfield is the largest ultra-high pressure gas fields in the world, with buried depth of 6000-10000 m and reservoir pressure of 115-14 MPa. Complex geological conditions, extreme working conditions and harsh corrosion environment bring great challenges to the integrity of high-pressure gas wells. This paper introduces the safety control technology for the ultra-high pressure gas wells, which ensures the safe production. For economic development ultra-high pressure gas field, it is essential to control the safety of high annular pressure. Field investigation of abnormal pressure indicates the previous design method and pressure control measures of two-stage barrier decreasing step by step in ultra-high pressure gas wells are difficult to meet the requirements of fine safety control. Therefore, the annular pressure safety control technology with the core of "two-stage well barrier equal strength design, annular pressure dynamic window control and pressure grading control" is established to realize the fine control of ultra-high pressure gas wells. Firstly,in the stage of ultra-high pressure gas well wellbore design, based on the equal strength design method, 140 MPa metal seal easily replaceable casing head and small coupling production casing are developed, which are integrated with the equal strength tubing string and Christmas tree to realize the "double insurance" of wellbore pressure. Even if the primary barrier fails, the secondary barrier can still prevent the leakage of high pressure gas.Secondly, based on international standards such as API RP 90-2 and ISO16530, the calculation method and control chart of annular allowable pressure dynamic window were established before ultra-high pressure gas wells were put into production. To improve the scientific foundation of annular pressure control, the damaged or failure mode of well barrier was taken into account to guide the annular pressure management. Finally, a management method was established for the production of ultra-high pressure gas wells, including risk assessment process and hierarchical management, and the hierarchical response measures are formulated to ensure the safety and stability of oil and gas wells, which can avoid the high risk and high investment brought by work over operations. Based on the safety control technology of ultra-high pressure annulus pressure in Tarim Oilfield, the proportion of oil casing annulus pressure in new wells is reduced from 40% to 0% within one year, and the overall annulus abnormal pressure well is reduced from 29.4% to 19.7%, which ensures the effective development and safe production of ultra-high pressure gas fields in Kuqa foreland basin.
Predictive Modelling of Carbon Dioxide Injectivity Using SVR-Hybrid
Authors: Mardhatillah Mutia Kharunisa , Md Yusof Muhammad Aslam , Sa'id Alva Andhika , Mohammad Fuad Iqmal Irsyad , Sokama Neuyam Yens Adams , Md Akhir Nur Asyraf
Published: March 2022

Southeast Asia is increasingly gaining attention as a promising geological site for permanent CO2 sequestration in deep saline aquifers. During CO2 injection into saline reservoirs, the reaction between injected CO2, the resident formation brine, and the reservoir rock could cause injectivity change due to salt precipitation, mineral dissolution, and fine particles migration. The underlying mechanisms have been extensively studied, both experimentally and numerically and the governing parameters have been identified and studied. However, the current models that have been widely adopted to investigate reactive transport and its impact on CO2 injectivity have fundamental limitations when applied to solve small, high dimensional, and non-linear data. The objective of this study is to develop efficient and robust predictive models using support vector regression (SVR) integrated with hyperparameter tuning optimization algorithms, including genetic algorithm (GA). To develop the model, 44 datasets are used to predict the CO2 injectivity change with its influencing variables such as brine salinity, injection flow rate, particle size, and particle concentration. The performance for each model is analyzed and compared with previous models by determination of coefficient (R2), adjusted determination of coefficient (R¯2), average absolute percentage error (AAPE), root mean square error (RMSE) and mean absolute error (MAE). The model with the highest R2 is selected as the predictive model for CO2 injectivity impairment during CO2 sequestration in a saline aquifer. The results revealed that both SVR and GA-SVR are able to capture the precise correlation between measured and predicted data. However, the GA-SVR model slightly outperformed the SVR model by a higher R2 value of 0.9923 compared to SVR with R2 value of 0.9918. Based on SHAP value analysis, brine salinity had the highest impact on CO2 injectivity change, followed by injection flow rate, particle concentration, and jamming ratio. It was also found that hybridization of genetic algorithm with support vector regression does improve the model performance contrary to single algorithm and contributes to the determination of the most impactful factors that induce CO2 injectivity change. The proposed model can be upscaled and integrated into field-scale models to improve the optimization of CO2 injectivity in deep saline reservoirs.
An Intelligent Selection Model for Optimum Artificial Lift Method Using Multiple Criteria Decision-Making Approach
Authors: Adam Abdelateef M. , Mohamed Ali Ahmed A. , Elsadig Abdelaziz A. , Ahmed Anas A.
Published: March 2022

The urge to design a selection model for a proper artificial lift system is noticeably escalating. It becomes prudent for the operator to consider most, if not all, of the available evaluation and selection methods. The concept behind it is to yield improved production at better conditions than could be expected.

The artificial lift includes five methods, and it is very crucial to select the best method considering the field conditions. In this paper, the best artificial lift is selected using multiple criteria decision-making model which is composed of the combination of Technique for Order Preference by the Similarity to Ideal Solution (TOPSIS) and the Analytic Hierarchy Process (AHP).

This new user-friendly model undertakes 15 essential technical factors sorted into three sets (well data, reservoir data, and quantitative data) each factor has its own weight in the final selection decision. Furthermore, the Results depicted in bar graph for further illustration. It is important to note that the final decision is entirely based on technical manners. Additional economic evaluation and detailed cost analysis are required when the model results in close outputs between alternatives.

Lastly, this integrated model was tested on 12 wells from block-4 and Block-6 in Sudan, inputs were real-time data from initial and status. Successfully, in the end, it yielded its theoretical results.
Riser-Less Surveillance for Aging Subsea Wellhead with Light Construction Vessel
Authors: Sripramote Pobtorn , Yingvorapant Worawit
Published: March 2022

Legacy Unocal have drilled hundreds of exploration wells between 1970's to 1990's in Gulf of Thailand with semi-submersible drilling rigs and drillships. Those exploration wells were plugged and abandoned as per the requirements back in the 1970's which the subsea wellheads were not cut and removed. According to asset retirement obligation, all structures above seabed need to be removed before returning concession area. These subsea wellheads are planned for cut and recovery, however, there are many uncertainties in regard to well conditions which includes trapped gas in casing annulus and casing corrosion. The correct and safest approaches to cut and recovery are to perform wellbore logging runs, gas evaluations, and casing wall thickness investigation.

The challenges faced in executing the logging runs in open water environment are to conduct safe, efficient, and reliable operations on Dynamic Positioning (DP) vessel which includes a work-class Remotely Operated Vehicle (ROV). The key factor is to attain as much information and quality logging data to engineer a successful cut and recovery campaign for these complex subsea abandonments.

To perform this operation in open water, it can lead to inaccurate logging data due to uncompensated conditions. An innovative solution was collaboratively invented and developed with Business Partners to deploy Logging Tower Subsea Deployment system (LTSDS) to mimic static logging condition. The tower is self-standing design with a capability to rig up on different type of wellhead. The trial was performed but had complications of deployment due to weather impact. The new method, non-compensated real time logging on Electric Line, was introduced to improve time spent per wells. The comparison of logging results from both methods shown similar and reliable log interpretations. The remaining wells were logged with non-compensated real time method, which reduce operational time by 45% as well as lower associated operational risks.

Other challenges encountered included logging depths 100 ft below mudline. Since some wells have shallower holdup depths or the tool could not pass due to encountering obstruction at shallow depths, gauge cutter was deployed with slickline unit to remove obstruction, followed by downhole high pressure jetting tool which was effectively helping to achieved logging intervals.

Interpretation of logging data were completed on more than 100 wells and results were used to engineer a detailed cut and recovery campaign and utilize new technology that the team had sourced to execute the operation.

With innovative designed set up of riser-less operation on light construction vessel, it is proven to meet objective of reliable logging data and cost efficiency and demonstrated flexibility for operation improvement.
Laboratory Study on the Use of Novel Biodegradable Scale Inhibitors Against Mixed Calcium Carbonate and Calcium Sulfate Scale
Authors: Husna Ully Zakyatul , Elraies Khaled Abdalla , Shuhili Juhairi Aris B. M. , Tewari Raj Deo
Published: March 2022

The development of the scale layers in oil and gas operation results in production losses and equipment instability because of pipeline blockage, energy leak, corrosion acceleration and severe accidents which will impact the safety of production. Among many types of scales, calcium carbonate and calcium sulfate are considered the most frequent, prominent and terrible. On the other hand, cellulose is a class of natural polymers and also contains abundant functional groups including hydroxyl, carboxyl, and amino groups, resulting in good chelation and dispersion effects. They possess good physical and chemical properties, thermal stability, and biodegradability, abundantly available and inexpensive which make them promising compounds for the creation of "green" oil field reagents, including scale inhibitor. In this study, we tested two types of biodegradable polymers named hydroxyethyl cellulose (HEC) and carboxymethyl cellulose (CMC) for application as calcium carbonate and mixed carbonate and sulfate inhibitors. There are three methods carried out, starting from the thermal stability test, static bottle test, and dynamic scale loop test. The inhibition performance tests were done at temperatures of 50°C, 70°C, and 90°C. The inhibitor concentration was varied from 10, 50, 100, 1000 until 10000 ppm. The results indicate that both HEC and CMC have the potency to be used as inhibitors for these two types of scales. Both results from the static bottle test and dynamic scale loop test indicate that HEC and CMC were able to inhibit the formation of the tested scale, yet they have not been able to completely inhibit 100% of scale formation.
IGUSA: Prediction of Ultimate Strength of Fixed Offshore Structures in Malaysian Waters Using Machine Learning Techniques
Authors: Ishak Muhammad Izzat Muhaimin , Lemma Tamiru Alemu , Muhammad Daud Mohd Hafis , Mohd Fatimi Norfazlin , A. Rahman Ahmad Rizal , A. Rahman Azam , Othman Abdul Rahim
Published: March 2022

IGUSA (Intelligent Global Ultimate Strength Analysis) is a tool developed by PETRONAS to predict the ultimate strength of a fixed offshore jacket platforms installed in Malaysian waters using machine learning techniques.

The ultimate strength, or more commonly represented by Reserve Strength Ratio (RSR), is a gauge of the robustness and redundancy inhibited in a fixed offshore structure. It is very useful in being an indicator for fitness-for-purpose of the platform and which is an integral part of Structural Integrity Management (SIM). However, a typical deterministic ultimate strength analysis for a fixed offshore structure is a time intensive process, using specialized software in the realm of plastic collapse analysis. As such, it is intended that machine learning techniques to be utilized to perform a prediction for the RSR, subsequently optimizing resources in SIM processes.

This paper will discuss the development of data-driven predictive model of IGUSA. Various machine learning techniques were experimented on PETRONAS' Global Ultimate Strength Analysis (GUSA) data. The objective is to obtain an accurate and reliable model to predict the RSR. Nonlinear regression using Artificial Neural Network (ANN) was found to provide the best model to predict the Base Shear Collapse, and hence the RSR for a typical jacket platform. The ANN model was incorporated into the IGUSA tool for deployment within PETRONAS. It is envisaged that IGUSA will be a valuable rapid screening tool for the typical platforms and the deterministic ultimate strength efforts can be focused on the more critical platforms.

Based on IGUSA development, the usage of machine learning techniques is proven to be useful in the structural engineering discipline. It is hoped that IGUSA will be able to assist PETRONAS and other Oil and Gas Operators in the region to optimize their resources in SIM processes.
A Workflow for Shale Play Exploration and Exploitation
Authors: Khan Muhammad Hanif , Yousaf Warda , Sadaqat Bilal , Javed Naila , Olukade Abdulrahman
Published: March 2022

This article aims to give an outline of an integrated geoscience approach that may apply in the initial identification of the shale play, address complex unconventional reservoirs, their associated challenges and finalise the pilot vertical wells to evaluate their potential.

Shale exploration depends on the proven source rock within the basin, so the availability of the required data, well data and seismic data in public domain for initial study and basin screening is usually easy. The investigation may start after knowing the well developed proven source rock in the basin. An extensive study of structure, tectono-stratigraphy, source rock and reservoir characterization, thermal maturity models and exploration strategy is required by using the regional tectonic history, drilled wells with multiple penerations in source rock, open-hole logs, mud samples and cores of the source rock to get the answers to the critical questions on the attributes that influence shale plays. Once these attribute questions have been satisfactorily confirmed to be in the required range or with an analog, that data can be utilized to locate possible sweet spots to drill pilot vertical wells with the goal of acquiring extensive coring, open hole logging and formation pressure testing data to identify the best candidates for further horizontal well evaluation.

This article highlights and demonstrates a possible step by step workflow for the selection of the shale play area, sweet spot and pilot vertical wells locations by using the schematic data maps, published material examples and building possible cut offs essential for exploration decision process.
An Era to Remember: Managing Offshore Drilling Campaign During World Pandemic Covid-19 Crisis
Authors: Ismail Ahmad Luttphi , Ishak M. Faizatulizuddin , Idris M. Idzarul , Abdul Hakim Hazlan , Othman M. Fikree , Chandran Kayathiri , Alias A. Hakim , Rozlan M. Rizwan , M. Ghazali M. Haziq
Published: March 2022

When the pandemic COVID-19 erupted and spreaded throughout the world, numerous rules and regulations were implemented to ensure the safety of everyone. The outcome of Covid-19 resulted in a global shutdown, where cases continued to grow rapidly that directly affected the normal processes in all business sectors. While the future is still uncertain, business plan must keep on progressing by managing all the obstacles to ensure the business goal is delivered efficaciously while keeping the impact as low as possible. In the early stage of the outbreak, there was limited knowledge and experience to manage a drilling campaign virtually, to ensure all plans are smooth despite all the restrictions to avoid additional cost and schedule impact to the company.

Since the outbreak was quite abrupt, the main challenge faced by the team was to ensure a continuous operation like any other year before but with additional enforcement of stringent COVID-19 SOP and to come up with new modus operandi with stringent SOP at every location. During this pandemic, the operation is exposed to the risk of being on standby mode due to equipment unavailability, unreadiness of manpower or delay in vessel movement. Knowing that drilling operation is so dynamic, that a slight change to the drilling sequence could lead to operation shutdown if the required services are not readily onboard. This uncomplimentary impact is due to the new rules or regulations implemented on the manpower and equipment movement to reduce risk of Covid-19 infection. Therefore, a thorough planning is crucial to ensure the success of operation, in fact a few fallback plans must be in placed to minimize the cost and schedule exposure.

This paper will address the challenges in managing equipment and manpower throughout the operation for BX-Project together with the solutions to ensure the governance, rules and regulations of Covid-19 are being followed. The approaches taken during this campaign is used as a baseline to run a drilling operation during Covid-19 pandemic in the upcoming year. Lessons learnt captured from this campaign can be replicated by other projects and finding the more efficient ways to implement the best practices. This pandemic has challenged our perseverance to deliver the project objectives while maintaining the dedication, health, focus as well as creativity to overcome unfamiliar circumstances.
Numerical Simulation of Whole Process Flow of Cementing Slurry
Authors: Liu Shan Shan , Li Rui Long , Yuan Wei Wei
Published: March 2022

Cementing is an important link in the process of oil and gas well construction. The quality of cementing directly affects the safety of next drilling, recovery capacity and life of later production. It is very important to accurately reflect and describe the dynamic changes of various underground parameters in the process of cementing for reasonable control of construction measures and guarantee the quality of cementing replacement. Based on the study of the dynamic process of cementing, the field equation is simplified to ID model by using the principle of momentum conservation and mass conservation, and the calculation model of cementing dynamic parameters at any time considering the effect of U-shaped pipe is established, including bottom hole pressure, friction, height and volume of vacuum section, static pressure in pipe and annulus, ECD and other dynamic parameters. The initial value problem is solved numerically by iterative method. The software of cement slurry flow simulator is developed, which is used to visually simulate the cement slurry flow process. The numerical model development software can be used to visually simulate the dynamic flow process of cement injection, which is suitable for complex wellbore structure and multi fluid injection. It can simulate the whole flow process of cement injection well, including the generation of U-tube effect, and analyze the variation law of dynamic parameters. The software can be used to simulate the dynamic flow process of cement injection, which is suitable for complex wellbore structure and multi fluid injection including the generation of U-tube effect, and analyze the variation law of dynamic parameters. Field data of a well was verified, and the results show that the proposed method can accurately calculate the flow parameters in the whole process of cementing, and can be used to guide the design of cementing operation. The innovation of this paper is to develop the simulation software of cementing slurry dynamic process. The function modules of the software use numerical model instead of empirical formula to improve the calculation accuracy of each parameter. The software has comprehensive functions, and gives the dynamic parameter change law of each stage in the fixed construction process. It has strong practicability and can well meet the requirements of on-site construction.
First Field Deployment of Erosion Control Technology for High Sand Production Wells in Offshore Malaysia
Authors: Myo Thant Maung Maung , Che Daud M. Faizal , Tuan Mahmud Tuan M. Yusoff , Kayat Zainab , Xian Lung Ivan Chee , Ngo Tran Nguyet , McNaught Rob , Wood Terry , Kiat See Chin
Published: March 2022

Sand production in oil and gas fields severely affects multiphase flow pipelines, piping and production facilities result in erosion damages and operational difficulties including valves, bends and other geometric fittings leading to loss of primary containment (LOPC). Presently, there is no technology available which can control sand erosion in real-time and help optimize production. This paper aims to present the first field deployment of a uniquely engineered flow modification device in debottlenecking a high sand producing well and maximizing production while reduction in erosion.

The sand erosion challenge can be overcome by using a patented Erosion Control Technology (ECT), to deflect and redistribute sand in the product flow stream. ECT has been successfully developed and validated through three test programs between 2016-2019. Following these, ECT technology maturity has been qualified for field application and selected to be deployed by PETRONAS, in one of the offshore fields located in Sabah, Malaysia, which is currently experiencing high erosion due to high sand production. The ECT pipe spool consists of a 3D printed Inconel 718 alloy insert integrated into carbon steel pipe to protect an elbow from sand erosion within the topsides wellhead piping system upstream of the wellhead choke. A control elbow upstream of the ECT device has also been installed to act as a mean of comparison throughout the pilot.

The protected elbow and control elbow will be monitored using manual UT at marked locations to measure localized wall thickness variation over the pilot testing period. The pilot is part way through its test program having been installed and commissioned at the end of 2021. Photos of the arrangement are shared in this paper along with the baseline wall thickness measurement.

The pilot trial success criteria are to show that the protected elbow will have minimal wall loss compared to the control elbow showing the effectiveness of ECT. The pilot expects ECT to reduce erosion due to sand and safeguard the facilities as well as maximize well production in preventing shortfall in total field production.
Novel Reservoir Sand Grain Size Map Based on Open Hole Gamma Ray Log as Im-Proved ThruTubing Sand Screen Size Selection Guideline on Tunu Multi-Layer Un-Consolidated Gas Reservoir
Authors: Setiadi Rahman , Jong Yulianto , Mahfudhin Nur , Muwaffaqih Mutawif Ilmi , Dading Albert Richal
Published: March 2022

Tunu is one of Mahakam fields with majority gas production. The depositional nature of fluvial with minimum tidal influence results in the signature of delta sedimentation by hundred layers of gas-bearing sand lenses as pay zone. They are constructed of unconsolidated clean and shaly sand reservoirs at the shallower burial and higher consolidation at deeper burial due to compaction and diagenesis. The unconsolidated section requires sand control as mandatory means to unlock it safely.

The combined challenge of numerous sand layers and marginal reserves makes it economically impossible to perform regular detailed physical sand grain assessment by individual conventional coring completed with Laser Particle Sieve Analysis (LPSA). An economic approach is through performing sand bailing. However, the bailed sand dry-sieve results were confusing with wide particle size distribution (PSD) curve variation from several well samples. Referring to this PSD uncertainty, installing straddled thru-tubing screen in front of the reservoir as sand control resulted in good production and plugged indication at the beginning of the initiative by utilizing a similar screen opening size. Thus, a new fit-for-purpose methodology was required.

A study to predict sand grain size on each reservoir target was initiated by analyzing three available shallow reservoir cores in Mahakam, which could cover most of Tunu's shallow sedimentation type. The result was that most of the sand grain size distribution on each sample core correlated with their calculated shale volume content (v-shale). Lower v-shale is respected to larger sand grain size. Unconsolidated Tunu Shallow reservoir doesn't contain any specific radioactive minerals. Thus, v-shale could be easily calculated from gamma-ray logs, which are always available on each reservoir target at any drilled wells. The relationship between sand grain size and v-shale was gathered on a single map.

The map was then validated by historical screen installation. Positive results were seen when screen size selection respects specific patterns on the generated sand map at the v-shale value of perforation intervals. Thru-tubing screen installation campaign was continued following the new sand map reference. It could deliver more than 80% successful installation with no plugging or sand at a new perforated reservoir when no screen integrity issue due to erosion was encountered.

This novel approach allowed better prediction of thru-tubing screen opening size requirements and perforation interval selection in Tunu unconsolidated reservoir and was successfully expanded in offshore Mahakam field at similar facies.
State of the Art Subsea Electric Control Systems
Authors: Champavere Claudine , Lacher Esteban , Moe Sigurd , Settiyannan Gunasekaran , Skrivervik Egil Mulstad
Published: March 2022

This paper explains the technology development to date of subsea electric valve actuation solutions for subsea production systems and discusses the roadmap for the future. Key experiences, and how these solutions are gradually becoming standard choice for many operators is discussed, from the subsea industry first applications 20 years ago.
Revised Methodology for Assessing Fixed Offshore Structures With Wave in Deck Loading
Authors: Lihin Zul Hilmi , Khan Riaz , Ishak M Izzat Muhaimin , A Rahman Azam , Kar Suman , Abdul Rahman Ahmad Rizal
Published: March 2022

Wave-in-deck (WID) loading has been an issue of concern for engineers dealing with the performance of fixed offshore structures. The issue is particularly relevant for reassessment of existing structures due to subsidence or structures designed to older codes and standards, where WID was not considered. WID issues often in costly subsea remediation, impact platform occupancy levels or premature decommissioning critical structures due to safety concerns.

The current in-house procedure is a simplified approach and revised to reflect the silhouette method and new industry requirements for the reliability of fixed offshore structures. The revised reassessment process shall enhance the methodology, based on widely accepted industry best practices.

The platform model is calibrated based on the measured in-field platform natural frequencies using a structural health monitoring (SHM) system, so that the reliability assessment can be performed on a structural model to validate the effects of the revised wave in deck approach. The revised methodology demonstrates the potential of unlocking structural capacity of offshore structures by removing conservatism normally associated with traditional reliability assessment methods, thus significantly improving the ability to achieve target structural reliability levels in a cost-effective manner.

A case study was embarked upon to demonstrate the benefit of the revised methodology for fixed offshore with insufficient air gap due to subsidence. The pilot study revealed significant improvement in ultimate strength of the structure using the revised methodology by more than 10% improvement in reserve capacity. This provides added benefits for increasing inspection intervals and optimizing the maintenance strategy due to risk reduction and avoidance of costly strengthening modification and repair (SMR).

The objective of the present paper is to establish an updated methodology to determine wave-in-deck loading for ultimate strength analysis. The scope of work of the study are as follow:

Perform a literature review of wave-in-deck assessment best practices, codes and standards. Develop assessment procedure based on international standards and research papers. Perform ultimate strength assessment based on revised methodology on a selected platform. Preparation of assessment methodology and case study report.
Alternate Foundation Concepts for Offshore Jackets in Calcareous Soils
Authors: Kumar Chaithanya , Pambudi Sandhria Ferriawan Agung , Salunke Milind Manohar , Rayappa John William
Published: March 2022

Calcareous soil type is found at many locations, requiring careful selection of foundation type. Calcareous soil is mostly or partly composed of calcium carbonate in the form of lime or chalk derived from the underlying chalk or limestone rock. North-West Shelf of Australia is an example of site which consists of carbonate soil types wherein the majority of existing offshore facilities and platforms being installed using Drilled and Grouted (D&G) piled foundations and in some instances using Gravity based foundations.

This paper discusses alternate foundation concepts on such soils, namely; (i) Micro-piles, and (ii) Inclined pile cluster, along with the common concepts of (iii) D&G piles and (iv) Gravity based foundations. The foundation concepts are discussed with focus on key aspects of the foundation structural configuration, vertical foundation capacity feasibility, and some serviceability related aspects. In addition, offshore operation and installation duration perspective are also discussed to provide some insight on how each foundation concept could suit the project preference which often influence the final selection of foundation concept. Risk/challenges and advantages of each concept are then summarized for overall comparison.