bluuebunny/crossref_metadata_2025_split huggingface dataset:
Data-Driven Multi-Asset Optimisation Under Uncertainty: A Case Study Using the New Indonesia's Fiscal Policy
Authors: Sajjad Farasdaq , Jaenudin Jemi , Chandra Steven , Wirawan Alvin , Prawesti Annisa , Muksin M. Gemareksha , Nugroho Wisnu Agus , Mujib Ecep Muhammad , Naja Savinatun 
Published: March 2021

Abstract
Optimizing multiple assets under uncertain techno-economic conditions and tight government policies is challenging. Operator needs to establish flexible Plan of Development (POD)s and put priority in developing multiple fields. The complexity of production and the profit margin should be simultaneously evaluated. In this work, we present a new workflow to perform such a rigorous optimization under uncertainty using the case study of PHE ONWJ, Indonesia.
We begin the workflow by identifying the uncertain parameters and their prior distributions. We classify the parameters into three main groups: operations-related (geological complexity, reserves, current recovery, surface facilities, and technologies), company-policies-related (future exploration plan, margin of profit, and oil/gas price), and government-related (taxes, incentives, and fiscal policies). A unique indexing technique is developed to allow numerical quantification and adapt with dynamic input.
We then start the optimization process by constructing time-dependent surrogate model through training with Monte Carlo sampling. We then perform optimization under uncertainty with multiple scenarios. The objective function is the overall Net Present Value (NPV) obtained by developing multiple fields.
This work emphasizes the importance of the use of time-dependent surrogate approach to account risk in the optimization process. The approach revises the prior distribution with narrow-variance distribution to make reliable decision. The Global Sensitivity Analysis (GSA) with Sobol decomposition on the posterior distribution and surrogate provides parameters’ ranking and list of heavy hitters.
The first output from this workflow is the narrow-variance posterior distribution. This result helps to locate the sweet spots. By analyzing them, operator can address specific sectors, which are critical to the NPV. PHE ONWJ, as the biggest operator in Indonesia, has geologically scattered assets, therefore, this first output is essential.
The second output is the list of heavy hitters from GSA. This list is a tool to cluster promising fields for future development and prioritize their development based on the impact towards NPV. Since all risks are carried by the operator under the current Gross Split Contract, this result is advantageous for decision-making process.
We introduce a new approach to perform time-dependent, multi-asset optimization under uncertainty. This new workflow is impactful for operators to create robust decision after considering the associated risks.
Prevention of Historically Challenging Sustained Casing Pressure from Shallow Gas Through Re-Engineered Cement Design and Execution Methodology
Authors: Ezani Farah Shakina , Thuzar Myat , Kumar Avinash Kishore , Lau Chee Hen 
Published: March 2021

Abstract
Sustained casing pressure (SCP) is a very costly event for any operator either at production phase or at the end of a well’s lifecycle. SCP is a result of incomplete hydraulic isolation across hydrocarbon bearing zone. In one of the gas fields in Malaysia, notoriously known for shallow gas hazard, drilled development wells which have reportedly been suffering SCP. In the past, various improvements in cement slurry design and placement methods were deployed in order to provide complete zonal isolation, especially at the shallow gas sand, yet SCP issue was encountered occasionally. In the current development campaign, different strategy to providing annulus sealing was adopted. This paper discusses proactive steps taken in the slurry design, fit together with the dual stage cementing approach, as a primary means of placing cement above the shallow hazard interval.
During the design phase, essential key parameters that would lead to successful placement of cement in the annulus as well as unique slurry design that suits for two stage cementing methods were studied. Risk involved in first stage cementing is one of the most important steps that should be analyzed in detail and put mitigation measures in place to ensure the second stage cement job can be performed as planned. In addition to the slurry properties, such as fluid-loss value, gas-tightness, etc., thickening time and top of cement (TOC) of the lead slurry in the first stage cement job has become enormously critical in designing dual stage cementing job in order to assure cement ports in the stage collar are not covered with hard cement forcing the termination of second stage job prematurely. Besides cementing design, careful selection of the stage collar location and casing annulus packer in the string is also of significant importance in leading to successful two stage cement job.
Two development wells with above approached has been delivered and no sustained casing pressure has been experienced. This proactive approach to use two stage cementing as primary plan has proven to successfully eliminate the risk of SCP, which was a frequent struggle in their sister wells drilled with primary cementing in the past in the same field.
The risk analysis combined with careful considerations of critical cementing design parameters and selection of stage tool location have become a novel approach to combat against SCP in this gas field.
Connecting the Dots - Creating Values in Wells Operation Through Collaboration and Innovation in Product Chemistry
Authors: Patmanesan Thanavathy , Razak M. Solehuddin , Devadass Lingges , M. Saleh M. Saufi , Khairi Nur Asyikin 
Published: March 2021

Abstract
Successful Wellbore Clean Up (WBCU) operation is one of the key aspects in delivering a high productivity well. Conventionally, in this phase, a series of surfactant and solvent pill is circulated downhole to "clean" the well. Poor job execution at this stage usually will result to tremendous amount of time to clean out the well or worst leaving the well with a "dirty" brine. Eventually this will lead to impairment in the well productivity.
The Operator experienced strings of non-performance in their WBCU operation. This is reflected by extensive circulation time and poor quality of the brine downhole. Coupled with pressing low crude oil price, the Upstream business of the Operator collaborated with their Downstream counterpart to co-create their own in house, low cost and high performance WBCU chemicals. Not only that the new chemicals resolved the operational issues faced by the Operator, it also created significant values within the company itself. The paper will discuss the process and implementation of the novel WBCU materials within the Operator's operation.
The performance of a WBCU surfactant is measured by its effectiveness in cleaning various types of downhole residues as fast as possible. The design of the new WBCU surfactant hinges on these criteria. In the lab, the performance of the material is measured using a "cleaning efficiency" test at different drilling fluids densities and WBCU formulations. Series of iterations were performed to determine the best chemistry for the WBCU surfactant. Finally, a field trial was conducted in one of the Operator's well, Well T-2 to gauge the product's performance in the real environment.
The field trial in well T-2 was successful in achieving a cleaner brine at a rate faster than well T-1, a similar well of the same campaign. Well T-1 used a conventional surfactant and solvent product in the current market. The WBCU used in well T-2 managed to reduce the final NTU of the brine up to 45% as compared to final NTU observed in well T-1. A reduction in the operation hours up to 4 hours was also seen in well T-2. This has contributed to cost savings in rig time up to USD 75K. The successful performance delivery of the Operator's in-house products has showcased a fruitful collaboration between different workstreams within the Operator. Deep understanding in the chemistry of solvent and surfactant from the Downstream business helps to solve the pain points by the Upstream business. Insights on product performance and applications are transpired within the team to innovate a solution with better performance at lower cost. This has paves way for more opportunities in product development especially in specialty chemicals.
Using Logging and Seismic Data to Identify Boundaries Between Different OWC Units in a Deepwater Carbonate Reservoirs
Authors: Ren Kangxu , Zhao Junfeng , Zhao Jian , Sun Xilong 
Published: March 2021

Abstract
At least three very different oil-water contacts (OWC) encountered in the deepwater, huge anticline, pre-salt carbonate reservoirs of X oilfield, Santos Basin, Brazil. The boundaries identification between different OWC units was very important to help calculating the reserves in place, which was the core factor for the development campaign.
Based on analysis of wells pressure interference testing data, and interpretation of tight intervals in boreholes, predicating the pre-salt distribution of igneous rocks, intrusion baked aureoles, the silicification and the high GR carbonate rocks, the viewpoint of boundaries developed between different OWC sub-units in the lower parts of this complex carbonate reservoirs had been better understood. Core samples, logging curves, including conventional logging and other special types such as NMR, UBI and ECS, as well as the multi-parameters inversion seismic data, were adopted to confirm the tight intervals in boreholes and to predicate the possible divided boundaries between wells.
In the X oilfield, hundreds of meters pre-salt carbonate reservoir had been confirmed to be laterally connected, i.e., the connected intervals including almost the whole Barra Velha Formation and/or the main parts of the Itapema Formation. However, in the middle and/or the lower sections of pre-salt target layers, the situation changed because there developed many complicated tight bodies, which were formed by intrusive diabase dykes and/or sills and the tight carbonate rocks. Many pre-salt inner-layers diabases in X oilfield had very low porosity and permeability. The tight carbonate rocks mostly developed either during early sedimentary process or by latter intrusion metamorphism and/or silicification. Tight bodies were firstly identified in drilled wells with the help of core samples and logging curves. Then, the continuous boundary were discerned on inversion seismic sections marked by wells.
This paper showed the idea of coupling the different OWC units in a deepwater pre-salt carbonate play with complicated tight bodies. With the marking of wells, spatial distributions of tight layers were successfully discerned and predicated on inversion seismic sections.
Application of Multi-Lateral Wells for Production and Enhanced Oil Recovery – Case Studies From Canada
Authors: Delamaide Eric 
Published: March 2021

Abstract
The use of multi-lateral wells started in the mid-1990s in particular in Canada, and they have since been used in many countries. However, few papers on multi-lateral wells focus on their production performances, thus what could be expected from such wells in terms of production and recovery factor is not clear and this paper will attempt to address that gap.
Taking advantage of public data, the production performances of various multi-lateral wells in Western Canada have been studied. In the cases reviewed in this paper, these wells always target a single formation; they have been used in a variety of fields and reservoirs, mostly for primary production but also for polymer flooding in some cases. Multiple examples will be provided, mostly in heavy oil reservoirs, and production performances will be compared to nearby horizontal and vertical wells whenever possible.
From the more classical dual and tri-lateral to more complex architectures with 7 or 8 laterals, and the more exotic, with laterals drilled from laterals, the paper will present the architecture and performances of these complex wells and of some fields that have been developed almost exclusively with multi-lateral wells. Interestingly, multi-lateral wells have not been used much for secondary or tertiary recovery, probably due to the difficulty of controlling water production after breakthrough. However, field results suggest that this may not be such a difficult proposition. One of the most remarkable wells producing a 1,250 cp oil under polymer flood has achieved a cumulative production of over 3MM bbl, which puts it among the top producers in Canada.
Although multi-lateral wells have been in use for over 25 years, very few papers have been devoted to the description of their production performances. This paper will bring some clarity on these aspects. It is hoped that this paper will encourage operators to reconsider the use of multi-lateral wells in their fields.
Multiplier Effects of Successful Projects: Replicable Solutions of Betty Redevelopment CSU
Authors: Ahmad Shatiry Muhamad Sahir , Ishak Zulhizzan , Kader Ibrahim Halizah , Sk A Aziz Thahir , Mohamed M Gaberalla , Teh Mei Li , Basri M Amir 
Published: March 2021

ABSTRACT
Brownfield oil and gas (O&G) project defines as a project involving upgrading or rejuvenating existing facilities to cater to production enhancement, extend production profile, and install new equipment or tie-in with new greenfield platform. This abstract serves to share the replicable solution on brownfield project management for Commissioning and Start-up (CSU) strategy for Offshore Field Rejuvenation and Redevelopment Project. Field A and Field B are two fields in the Baram Delta Operation (BDO) in Malaysian Waters. Field A and B were first discovered and started its production in the early 1970s, putting the existing facilities’ current service life at an average of 40 years.
Field B is within the Baram Delta in the South China Sea, about 40km from Miri, Sarawak. Field B plan for Brownfield Project is rejuvenation and redevelopment scopes to cater to the upcoming new installation of 3 wellhead platforms (WHPs) and one Central Processing Platform (CPP). The redevelopment project aim is to install new topside facilities to revive and upgrade platforms in Field B. The new facilities installed on the platform are new knock out drum, flare boom, Diesel Engine Generator (DEG), Gas Engine Generator (GEG), Diesel Tank, Sump Tank, HP Flare Knock up Drum Pump, and Instrument Air Package. This project is also part of the Enhanced Oil Recovery (EOR) project to increase overall Field A & B production from 60kbpd to 120kbpd total liquids.
Performance Improvement of Wells Augmented Stuck Pipe Indicator via Model Evaluations
Authors: Meor Hashim Meor M. , Yusoff M. Hazwan , Arriffin M. Faris , Mohamad Azlan , Tengku Bidin Tengku Ezharuddin , Gomes Dalila 
Published: March 2021

Abstract
The advancement of technology in this era has long profited the oil and gas industry by means of shrinking non-productive time (NPT) events and reducing drilling operational costs via real-time monitoring and intervention. Nevertheless, stuck pipe incidents have been a big concern and pain point for any drilling operations. Real-time monitoring with the aid of dynamic roadmaps of drilling parameters is useful in recognizing potential downhole issues but the initial stuck pipe symptoms are often minuscule in a short time frame hence it is a challenge to identify it in time. Wells Augmented Stuck Pipe Indicator (WASP) is a data-driven method leveraging historical drilling data and auxiliary engineering information to provide an impartial trend detection of impending stuck pipe incidents. WASP is a solution set to tackle the challenge. The solution is anchored on Machine Learning (ML) models which assess real-time drilling data and compute the risk of potential stuck pipe based on drilling activities, probable stuck pipe mechanisms, and operation time. The output of the analysis is built on a warning and alarm system that can be utilized by the engineers to refine and optimize the well construction activities; tackling the stuck pipe issue before it manifests. This solution is evaluated by comparing historical and real-time drilling parameters with the prediction data to generate an error analysis. On top of that, a confusion matrix is tabulated based on the analysis of warnings and alarms raised by the solution to rule out Type 1 and Type 2 errors. The WASP solution has demonstrated tolerably accurate predictions of drilling parameters with minimal warnings and alarms error. With the solution, the stuck pipe issue can be identified hours earlier before the actual stuck pipe was reported in the historical well. It is a powerful tool with the capability to pinpoint possible stuck pipe mechanisms for engineer's immediate analysis and intervention. Value creation from the WASP solution has been massive with a reduction in manhours of analysis, potential NPT events, and unexpected operational costs. Data-driven techniques are effective in preventing stuck pipe incidents and will be scalable to tackle other downhole issues such as loss of circulation, well control, and borehole instability.
Borehole-Driven 3D Surface Seismic Data Processing Using DAS-VSP Data
Authors: Yu Gang , Wu Junjun , Chen Yuanzhong , Wang Ximing 
Published: March 2021

Abstract
A 3D surface seismic data acquisition project was conducted simultaneously with 3D DAS-VSP data acquisition in one well in Jilin Oilfield of Northen China. The 3D surface seismic data acquisition project covered an area of 75 km2, and one borehole (DS32-3) and an armoured optical cable with high temperature single mode fiber were used to acquire the 3D DAS-VSP data simultaneously when the crew was acquiring the 3D surface seismic data.
The simultaneously acquired 3D DAS-VSP data were used to extract formation velocity, deconvolution operator, absorption, attenuation (Q value), anisotropy parameters (η, δ, ε) as wel as enhanced the surface seismic data processing including velocity model calibration and modification, static correction, deconvolution, demultiple processing, high frequency restoration, anisotropic migration, and Q-compensation or Q-migration. In this project, anisotropic migration, Q-migration was conducted with the anisotropy parameters (η, δ, ε) data volume and enhanced Q-field data volume obtained from the joint inversion of both the near surface 3D Q-field data volume from uphole data and the mid-deep layer Q-field data volume from all available VSP data in the 3D surface seismic surveey area. The anosotropic migration and Q-migration results show much sharper and focussed faults and and clearer subsutface structure.
Production Tubing Leak Repair Using Reinforced Thermoplastic Pipe
Authors: Oloruntobi Olalere Sunday , Chandran Prasanna Kumar , Abu Bakar M Azuan , Zulkarnain Nurul Nazmin , A Rahman Hasrizal , Das Debasis Priyadarshan , Tiwari Pankaj Kumar , Yahaya Azahari 
Published: March 2021

AbstractOperators are faced with never-ending well integrity issues relating to tubing leaks. This situation is particularly important in oil and gas wells that are producing in corrosive environments. When a well can no longer be safely produced due to well integrity issues relating to tubing leaks, an expensive workover is often performed to restore the tubing integrity. To improve the economics of a well intervention involving tubing leak repairs, a new cost-effective method is being proposed. The novel technology involves the installation of reinforced thermoplastic pipe (RTP) inside the existing tubing to isolate multiple leaks using a coiled tubing unit or an E-line. The RTP is engineered for downhole applications with custom designed connectors and accessories. It is designed to handle corrosive fluids (CO2 and H2S) and prevent downhole erosion caused by sand production. The RTP can be used to eliminate tubing – annulus communication in both producers and injectors with full compliance to well integrity management system. The results of the field trial in a gas injector well in Malaysia basin show that the RTP can provide a reliable means of restoring and enhancing the production of oil and gas with considerable cost savings (up to 80% cost reduction when compared to a conventional workover). In most cases, the high cost associated with a conventional workover can make it uneconomical when compared to the expected hydrocarbon recovery from the well, resulting in production deferment (well shut-in). The RTP can significantly increase the viability of repairing a larger percentage of the wells that are shut-in due to the loss of tubing integrity when the hydrocarbon recovery from the well is insufficient to justify a full workover. The significant cost savings provided by the RTP would dramatically improve economics and would likely result in more reserves recovered. The RTP also has a smoother surface that contributes to minimum friction and reduces the risk of scales formation when compared to the steel tubing of the same internal diameter.
Design and Execution of the First Large-Scale Polymer Injection Pilot in Sirikit Oil Field
Authors: Wuttipittayamongkol Weeraya , Trinavarat Pannapon , Nuntaprayoon Warisa , Pancharoen Monrawee , Laochamroonvorapongse Rapheephan 
Published: March 2021

Abstract
Becoming more mature with field-wide water flooding implementation for more than 30 years, Sirikit Oil Field (S1) is going forward to the next rejuvenating step of enhanced oil recovery (EOR). Generally, the field contains light oil (40° API) in highly stratified sand-shale sequences with low net-to-gross ratios. High reservoir temperature, low permeability, and high water cut observed from production make it even more challenging for polymer injection projects. Nonetheless, the success from a small-scale field trial has shown a promising future of EOR application in the field and brought an execution of the first large-scale polymer injection pilot.
Polymer screening laboratory tests, a reservoir simulation study, data acquisition program and techniques, injectivity tests, polymer injection unit design, and risk assessment were parts of the pilot preparation, in which the key learnings from the previous pilot have been incorporated. The gathering and determination of baseline parameters including production performance, injection profiles, reservoir fluid saturation profiles, etc., were registered for ultimate evaluation. Then, the continuous polymer injection has been started since October 2019 in two separated fault blocks where 12 injectors and 20 producers are located in different injection patterns.
During several months of polymer injection, both foreseen and unforeseen changes have enlivened the pilot management. Although the injectivity test with polymer solution prior to the pilot demonstrated no injection difficulty, several wells have shown injectivity deterioration with time. Mechanical degradation is induced in these wells by the installation of flow restriction devices to lessen solution viscosity and, hence, prolong polymer injectivity. Well integrity issues and artificial lift breakdown negatively affect field production and close-in wells make it harder for voidage replacement control. Immediate troubleshooting and close monitoring have been placed and eventually leads to the recognition of encouraging results. Polymer helps improve vertical injection profiles as seen from injection logging. Saturation logging presents a sign of oil saturation decrease around the wellbore area. Reduction of water cut and rise of oil production have pleasantly come after a few months from the start. Intensive surveillance program will be continued over the course of pilot injection.
The critical success of the EOR pilot execution depends on the detailed planning, prudent surveillance and comprehensive evaluation. Sirikit oil field is moving to a turning point and the pilot outcome would lead the way to a further milestone, so as to avoid premature end of the field's production.