bluuebunny/crossref_metadata_2025 huggingface dataset:
Digital Oil Model Development and Verification
Authors: Hon Vai Yee , Mohd Saaid Ismail , Ivy Chai Ching Hsia , M. Fauzi Noor 'Aliaa , Deguillard Estelle , Male Jan van , Handgraaf Jan-Willem
Published: March 2021

Advances in digital technologies have the potential to enhance model predictive capability and redefine its boundaries at various scale. Digital oil with accurate representation of atomistic components is a powerful tool to analyze both macroscopic properties and microscopic phenomena of crude oil under any thermodynamic conditions. Digital oil model presented in this paper is the key input in molecular chemistry modeling for designing chemical enhanced oil recovery formulation. Hence, it is constructed based on a fit-for purpose strategy focusing in oil components that have large contribution to microemulsion stability.

Complete crude oil composition could comprise over 100,000 components. Lengthy simulation time is required to simulate all crude oil components which is impratical, despite the challenges to identify all crude oil components experimentally. Therefore, we established a practical experimental strategy to identify key crude oil components and constructed the digital oil model based on surrogate components. The surrogate components are representative molecules of the volatiles, saturates, aromatics and resins. Two-dimensional digital oil model, with aromaticity on one axis, and the size of the molecules on the other axis was constructed. We developed algorithm to integrate nuclear magnetic resonance response with architecture of the molecular structure. A group contribution method was implemented to ensure reliable representation of the molecular structure.

We constructed the digital oil models for a field in Malaysia Basin. We validated the physical properties of the digital oil model with properties measured from experiment, predicted from molecular dynamics simulation and calculated from quantitative property-property relationship method. Good agreement was obtained from the validation, with less than 5% and 13% variance in crude density and Equivalent Alkane Carbon Number respectively, indicating that the molecular characteristic of the digital oil model was captured correctly. We adopted the digital oil model in molecular chemistry modeling to gain insights into microemulsion formation in chemical enhanced oil recovery formulation design. Digital oil is a robust tool to make predictions when information cannot be extracted from experimental data alone. It can be extended for engineering applications involving processing, safety, hazard, and environmental considerations.
Rotary Steerable System Design Optimisation with Roller Reamers Prevents Stuck Pipe Events
Authors: Yadav Anurag , Abdelazeem Omar , Chebab Mohamed , Shata Atef , Al-Othman Ahmad , Al-Mulaify Mohammad
Published: March 2021

An increasing deployment of rotary steerable system to drill through complex reservoirs demands considerable gains in operating efficiency. It is a known fact that one of the main drilling challenges faced by oil & gas industry is stuck pipe. The risk of stuck pipe is particularly elevated when using a rotary steerable system tool to drill through formations having geo-mechanical instability and alternating hard-soft interbedded layers. This elevated risk is due to the pivot stabilizers, typically used on such tools which have a limited flow by-pass area and high side loads at the contact points with formation. This study showcases how in geo-mechanically unstable formations, a stabilizer in a rotary steerable system tool can be replaced with a roller reamer technology to reduce stuck pipe events while still delivering steerability objectives.

Roller reamers are known to deliver reduced contact forces and torque. The analysis focuses on how roller reamer technology was used to prevent rotary stalling of a drill string while drilling, which inadvertently had been a root cause in most stuck events. It also describes how BHA was optimized to achieve directional objective. Further, it discusses how drilling execution and monitoring procedures were modified to ensure stuck pipe is avoided without compromising directional yield of the BHA.

Results are presented from actual wells, demonstrating an outstanding achievement of no stuck events on 4 back to back wells after multiple incidents of stuck pipe and lost in hole on previous wells. The best practices followed to ensure safe drilling are explored to highlight roles played by roller reamer replacement of pivot stabilizer in rotary steerable system tool, BHA optimization and real time drilling monitoring. Results prove that an engineered application of proper BHA design and effective drilling execution & monitoring can deliver efficient operations, even in most complex drilling environments.
An Innovative and Transparent Negotiation Mechanism for the Petroleum Contracts to Develop Marginal Oil Fields
Authors: Shiaoi Tsung-Wen
Published: March 2021

This study is to propose a transparent mechanism among host governments and international oil companies (or IOCs) so an amicable "win-win" situation can be achieved on the negotiation of the petroleum contracts for the development of marginal fields.

Marginal field has various definitions. It can be a field with recoverable reserve not exceeding 30 million barrels of oil or 500 billion standard cubic feet of natural gas (Abdul Razak 2011, Malaysian Petroleum Income Tax Act 1967). It also can be a field, somehow "stranded", needs an oil price of US$60/bbl to be commercial (Aziz 2019). Or as simpe as it can be, a marginal field in Nigeria is any field being left unattended for more than ten years from the date of discovery (Auwalu 2020). In this paper, the author recommends that a marginal field be difined as any undeveloped field with a zero present value at 10% discount rate (or PV10 Value = 0) based on the average commodity price of previous 12 months’ first-day-of-the-month prices. This definition is conformable to the SEC pricing guidelines for publicly traded IOCs in the U.S.A. (Scheig n.d.).

Host governments endeavor to bring foreign fund and technology to develop their hydrocarbon resources effectively for the benefit of national welfare. IOCs are eager to expand into other promising areas for more hydrocarbon reserves in order to strengthen the balance sheets. A well-designed petroleum fiscal regime can thus achieve the balance between host governments and IOCs (Tordo 2007).
Application of the Jet Pump to the Slim Hole Production Wells at Onshore Thailand
Authors: Ishihara Ryujiro , Higuchi Naohide , Mikami Yohei
Published: March 2021

This is a case study to establish the positive result of an artificial lift application of the jet pump (JP) system using the coiled tubing (CT) and the macaroni tubing (MT). It is applied to the monobore completions for the slim-hole production wells on BURAPA-A oil field, onshore Thailand, implemented by Siam Moeco Ltd. (SML, Affliated Company of Mitsui Oil Exploration Co., Ltd.). As a result of the JP introduction, the resulting production decline rate was lower and the recovery factor more than doubled, which extended field life longer than expected. SML succeeded in discovering the method to minimize the capital cost while maximizing the oil recovery with the JP system. This method has given us the chance to conduct a smaller-scale well intervention operation with only minor modification of the wellhead. We believe that it is an adequate artificial lift application for the small-size oil field.

Some important lessons for the small pipe size operations were learned in this process. A pin-hole leak was detected in the CT for the main production well due to erosion and corrosion by continuous high-pressure pumping for around two years after the installation of the JP completion. After reviewing the new completion design, the type of deployment pipe was converted to the MT, which is thicker and has higher integrity than the CT. Consequently, there have been no integrity issues for the deployment pipes since the production was resumed with the new completion. In addition, using the multi finger caliper tool, it was detected that the thickness of the production tubing at the jetting area was significantly eroded, showing that the JP system has the possibility to risk the integrity for the outer string.

The JP completion is a validated technology to apply for the slim-hole monobore completions to increase the recovery factor and minimize the implementation cost. In addition, the well integrity risk by the JP application to the slim-hole monobore completions was revealed, and new insights were gained, resulting in some pros and cons comparing the two types of the deployment pipes (CT & MT).
The Color of Energy: The Competition to be the Energy of the Future
Authors: Lau Hon Chung
Published: March 2021

Energies may be described as brown, blue or green. Brown energies are CO2-emitting fossil fuels. Blue energies employ carbon capture and storage (CCS) technologies to remove the emitted CO2 from brown energies. Green energies are zero or low CO2-emitting renewable energies. Likewise, energy carriers such as electricity and hydrogen may be described as brown, blue or green if they are produced from brown, blue or green energy, respectively. The transition from a high carbon intensity to a low carbon intensity economy will require the decarbonization of three major sectors: power, transport and industry. By analyzing the CO2 intensity and levelized cost of energy (LCOE) of energy and energy carriers of different colors, we show that renewable energies are best used in replacing fossil fuels in the power sector where it has the most impact in reducing CO2 emission. This will consume the majority of new additions to renewable energies in the near to medium future. Consequently, the decarbonation of the transport and industry sectors must begin with the use of blue electricity, blue fossil fuels and blue hydrogen. To achieve this, implementation of large-scale CCS projects will be necessary, especially outside of USA and northern Europe. However, this will not happen until significant financial incentives in the form of carbon tax or carbon credit becomes available from national governments. Furthermore, private-public partnership and intergovernmental cooperation will be needed to implement these CCS projects.
Fines Migration Behavior During Cyclic Injection and Production of Underground Gas Storage Wells
Authors: Chen Mingjun , Shao Jiaxin , You Lijun , Kang Yili , Meng Seng , Yang Guang
Published: March 2021

Different injection and production pressure modes for underground gas storage have great differences on the permeability of formation rocks. In this paper, core flow experiments are designed and carried out to simulate the real pressure gradient of the injection and production in underground gas storage, and these experiments are carried out under in-situ stress conditions. The permeability and turbidity of core outlet were monitored during the experiment. The experimental results show that under different injection-production pressure modes, the permeability changes and the turbidity at the core outlet changes. It was observed by scanning electron microscope that there were fines on the fracture wall after the experiment. Analysis shows that fine migration is the main reason for the change of permeability under different injection-production pressure modes.
Small Scale Skid-Mounted Natural Gas to Hydrogen Production System Provides Competitive Hydrogen for China
Authors: Song Pengfei , Wang Rui , Sui Yiyan , Shan Tongwen , Hou Jianguo , Wang Xiulin
Published: March 2021

Because of its convenience, high efficiency and low cost, small-scale skid-mounted hydrogen generator has become a hydrogen-production object of intense research efforts worldwide and has broad prospects in application. We analyze the technical points and difficulties in detail of this kind of on-site compact hydrogen generators from natural gas, by each section in the production process. It is suitable for integrated hydrogen refueling stations due to easy transportation and installation. Related applications are introduced by comparing the technical parameters of recent typical products in the world. Meanwhile, we calculate that the full life cycle cost of hydrogen from skid-mounted hydrogen generator from natrual gas can achieve less than 40CNY / kgH2, which is more economic than other possible hydrogen sources and transportation modes of a hydrogen refueling station. Although the advantages mentioned above, we point out that technology innovation is still desirable, especially in the process of reforming, automatic control, system integration and catalysis, to realize the minimization of skid-mounted hydrogen generators base on natural gas, for its further and wider application in the future.
Robust Dynamic Toolface Calculation for Automatic Steering Control with Rotary Steerable Systems Under Extreme Conditions
Authors: Ramakrishnan Ganesh , Demirer Nazli , Tilley Jim
Published: March 2021

Reliable toolface calculation is essential for achieving robust automatic steering control with rotary steerable systems (RSS). For RSS with fully rotating sensor packages, this task becomes particularly challenging under extreme conditions, where signal-to-noise ratio (SNR) of measurements from one or more sensors reduce significantly (e.g., while drilling near-vertical wells, along dip, towards magnetic north, in the vicinity of casing and/or under severe vibration and stick-slip). To ensure robust toolface control for fully rotating RSS under these conditions, this paper proposes a novel dynamic toolface calculation method.

The proposed dynamic toolface calculation method of the new-generation fully rotating RSS overcomes the challenge of achieving robust toolface control despite extreme drilling conditions, by bringing together real-time health monitoring, online sensor calibration and novel sensor fusion techniques. Considering that robust toolface control is the heart of any drilling automation architecture with RSS, this technology is key to enable advanced drilling control strategies in the future.
A New Method of Pressure Analysis of Well-Test Data from a Well in a Multi-well Reservoir with no Flow Boundary Condition & New Diagnostic Plots to Differentiate Between the Boundary and Interference Effects
Authors: Cobanoglu Mustafa
Published: March 2021

If the interference effect is not considered for well test interpretation, it could lead to wrong analyses especially in boundary identification. In addition, there are some case where interference effects might be hidden where it may not be obvious due to data uncertainty. Therefore, special diagnostics of the multi well interference models will be required to differentiate between the boundary and interference effects. In addition, there is no analytical method for a well in a multi-well reservoir with no flow boundary condition.

In this paper a new method was developed to model Pressure Analysis of Well-Test Data from a Well in a Multi-well reservoir with no flow boundary condition. It covers;

Derivation of the analytical model, based on the superposition principle, with and without "no flow" boundary condition; Modeling of various combination of testing & interfering well cases (i.e. testing well is on production or shut-in while interfering well is on production or shut-in) Modeling of various combinations of testing & interfering well rate cases (i.e. production or injection, rate variations) Modeling of various number of interfering well cases (i.e. location and well count) Investigation deeply on how to differentiate between the boundary and interference effects (or vice versa) and developing the special diagnostics to able to detect interference effect directly.

Results are shown that 1) the multi-well interference effect with and without no flow boundary condition has huge impact on the well test interpretation and this effect might be interpreted as a boundary effect if interference is not considered. 2) Build-up (BU) behavior of testing well is depending on whether interfering well is shut-in or producing. If interfering well is producing, pressure derivative of BU curve is concave down and If the interfering wells are shutting in, pressure derivative of BU curve is concave up 3) the interfering well rate is affecting magnitude of impact on pressure derivative and the higher the rates, the bigger the response 4) the interfering well distance is affecting the timing of deviation on pressure derivative and the closer the distance, the quicker the response

Study also concluded that there are 3 special characteristics, which only exists in interference cases, and which does not exist in boundary cases. Therefore, those characteristics can be used to differentiate between the interference and boundary effects. Those are 1) Pressure decrease or rise at the beginning of well testing 2) the drawn-down (DD) and BU pressure derivatives in Log-Log plot are different (i.e. when BU is concave up, DD is concave down or vice versa) in case of interfering well is on continuous production 3) The consecutive BU's (or DD's) pressure derivatives on Log-Log plot are different and changing over time
Feasibility Study on Optimisation of Material Selection for High Temperature Sour Gas Producer
Authors: Nordin M. Helmi , Moh Wahi M. Wahidullah , Sashidharan Amresh , A. Karim Nurfuzaini , Ramli Alif Syahrizad
Published: March 2021

K field is a green field in East Malaysia with prolific gas reserves that is being developed with six high rate gas producing wells from high temperature (190 °C) carbonate reservoir. Tubular material feasibility study is one of the key subjects of scrutiny when it comes to completing wells in high temperature environment coupled with existence of significant level of H2S and CO2 contents. Material testing was conducted at the specified test environments (102 bar CO2 + 120ppm H2S) and load cases to assess susceptibility of Martensitic Stainless Steel to Stress Corrosion Cracking (SCC), corrosion rate and compatibility with completion brine. The aim was to optimize the material selection that is fit for purpose (lower completion and flow-wetted area of production casing) and reduce well cost up to USD 2.5 million.

The base case of material selection for flow-wetted section is 17CR110 ksi, which meets the design requirements of these wells based on fit for purpose test conducted in the data base. Flow-wetted section in this case is production liner and flow-wetted section of production casing below production packer. Super 13CR -110 ksi and 15CR125 ksi material grades were considered for design optimization for this section of interest. Four Point Bend Method was used for SCC test sets while weight loss method for corrosion rate measurement. For brine compatibility test, calcium bromide (without additive) was used as test solution for 17CR 110 ksi, 15CR 125 ksi and Super 13CR -110 ksi with elevated temperature of 190 °C.

Post-test assessment was conducted by visual examination by stereomicroscope to check for surface indication and dye-penetrant examination to determine any indication of cracks. It was observed that the Super 13CR -110 ksi and 15CR 125 ksi test specimens survived the test with no pitting observed. Meanwhile, test specimens were weighed to determine corrosion rates, resulted to Super 13CR -110 ksi sample having an average corrosion rate of 0.2195 mm/year. This translates to less than 30% weight loss throughout well production life and therefore accepted for open-hole production liner and production casing flow-wetted section.

Key enabler in this design optimization effort is the understanding of the Stress Corrosion Cracking for martensitic stainless steel in high temperature sour environment where commonly, martensitic stainless steel (Super 13Cr / Modified Super 13Cr) working temperature is 165 °C. The test manages to extend the working temperature up to 190 °C.
Successful Application of Rigless Fully Retrievable ESP System in Bohai Offshore Oilfield, China
Authors: Shang Baobing , Li Junfei , Fang Tao , Yu Fahao , Han Xiaodong
Published: March 2021

In bohai offshore oilfield, about 98% oil wells produce with electric submersible pump (ESP). For the common ESP system, workover is needed to replace the failed pump about every 4 years, resulting in significant operation cost and production lost. To solve this problem, a new type of rigless fully retrievable electric submersible pump (RFR-ESP) is developed and applied in bohai oilfield.

This paper mainly introduces the technical details of the used RFR-ESP system, and the real application effects in typical wells. This new system consists of downhole permanent part and retrievable part, with the power cable clamed externally along with the tubing. The core of the system is a specially designed wet connector system. Through this connector, any ESP manufacture's equipment can be used. For this technology, the retrieval of ESP can be finished by standard oilfield wireline operation, and no rig workover is required any more. Till now, two different systems suitable for 7″ tubing and 5-1/2″ tubing have been developed in order to meet the yield of different wells.

Bohai oilfield installed the first RFR-ESP in 2013. Up to now, 6 wells have applied this technology, including one water source well and five oil wells. The longest running time of the ESP is about 2000 days, and it is still in service now. The maximum liquid production is about 2800m3/d. For this new system, the workover time of ESP replacement reduces from 10 days to about 2 days comparing to the traditional rig workover process, and the number of the workover operators reduces from 30 to about 10. All of these are helpful to reduce the workover cost and the production lost. Besides, several problems encountered in the wells, such as power cable failure provides valuable field experience for the promoted application in bohai offshore oilfield.

The successful application of this technology indicates that it has the potential to lower ESP operating costs, and even improve the artificial lift status of offshore oilfield. What's more, this new system is expected to be used in unmanned platform, thus no workover boat is needed any more, which will drastically cut down the development cost.
Combining Sparse Data with Reaction Kinetics Using Fuzzy Logic to Predict Reservoir Souring
Authors: Kathrada Muhammad
Published: March 2021

Hydrogen Sulphide (H2S) is a colourless, flammable and highly toxic gas with a strong odour of rotten eggs that is found in many reservoir fluids and aquifers in the world. This gas is commonly a result of "reservoir souring" – a process which increases the H2S concentration. Increasing amounts of this gas pose serious health, safety and environmental concerns. This can result in significant costs associated with replacement of downhole and surface equipment and increased processing costs, but more lethally a potential loss of life.

Many reservoirs particularly those undergoing waterflooding face increasing levels of hydrogen sulphide (H2S) production with time. H2S is a highly toxic gas that can be fatal even at low concentrations. Being able to predict the risk potential of a particular reservoir to increasing H2S production with time would be highly valuable. The objective is to determine apriori whether a reservoir would likely see dangerously high levels of H2S being produced during the lifetime of the reservoir, and if so, be a catalyst in supporting further investigation and mitigation of H2S early in the reservoir development.

There is very little published field data with regards to reservoir souring, hence a purely data driven model would not be possible to create. However, we do have a good understanding of the reaction kinetics that goes into the biological process that generates H2S. To this end the best modelling paradigm that can assimilate sparse data with first principles dynamics is fuzzy logic. A fuzzy logic model has been built around the reaction kinetics and then conditioned to the published field data. The model created matches the published field data fairly well. It is now a ready tool that can be used by engineers to make a quick assessment of their reservoirs before going into full blown expensive sampling and laboratory analysis.

The novel aspect of this paper is being able to use fuzzy logic to combine the first principles chemistry together with sparse data to produce a model that can be used practically. Fuzzy Logic has been out of the news of late as machine learning and neural networks are the current hot potatoes, however it is often overlooked that fuzzy logic can still be used in low dimensional cases where only sparse data is available.
Effect of Nano Carbon Spheres on the Properties of Oil-Based Drilling Fluids under High Temperature Conditions
Authors: Zhong Hanyi , Kong Xiangzheng , Qiu Zhengsong , Huang Weian , Zhang Xianbin , Zhao Chong
Published: March 2021

Owing to superior temperature stability in comparison with water-based drilling fluids, oil or synthetic-based drilling fluids are generally preferred for high temperature and high pressure (HTHP) formations. However, the thermal degradation of emulsifiers and polymeric components under HTHP conditions that results in loss of rheological and filtration control, barite sag or even fluid phase separation also occurs. It is a challenge to sustain these properties stable under such harsh condition.

Since nanoparticles have potential to provide better thermal stability, improved filtration loss as well as emulsion stability, the aim of this study is to investigate the effect of nano carbon spheres on the properties of oil-based drilling fluids under high temperature conditions. The nano carbon spheres were synthesized with the hydrothermal reaction of glucose. The influence of nano carbon spheres on the rheological, filtration, emulsion stability, settlement stability, as well as lubricity of a typical mineral oil-based drilling fluid with oil to water ratio of 80:20 was investigated before and after thermal aging at 180 and 200°C, respectively.

The structure characterization showed that the uniform hard nano carbon spheres exhibited intermediate wettability. Laboratory performance test indicated that, for the oil-based drilling fluid, the addition of nano carbon spheres improved the rheological properties in terms of yield point and the ratio of yield point to plastic viscosity, which is beneficial for transporting of drilling cuttings. After thermal aging at 200 °C, the filtration loss volume was reduced as high as 70%, and desirable filter cake quality was obtained by incorporation of 1.0 wt% spheres, meanwhile the electrical stability was improved both before and after thermal aging. Furthermore, the fluid formulated with the nano carbon spheres generated better barite sag control. The polarizing microscope observation showed that the nano carbon spheres accumulated at the water-oil interface and formed a steric barrier which probably explained the reason of the above enhanced performance.

The green synthetic routes and environmental friendly characteristics of the nano carbon spheres, in combination with the excellent properties suggested that the nano carbon spheres hold potential as multi-functional additives for formulating oil-based drilling fluids for HTHP drilling operations.
A Story of Material Selection For Completion Tubing in HPHT Gas Fields in the Past 20 Years, Western China
Authors: He Xinxing , Wang Kelin , Fan Wei , Liu Hongtao , Long Yan , Xie Junfeng , Fu Anqing , Deng Peng , Jiang Tianhong
Published: March 2021

Kuqa foreland basin, which is located in the western of China, has the characteristics of HPHT with high CO2 partial pressure, and covered Yaha, Kela, Dina, Dabei, and Keshen gas fields. This story dated back to 2000 year that Yaha gas field was put into production, and the reservoir temperature 140°C, pressure 56 MPa, depth 4900-5300 m, and CO2 concentration 0.7-1.3 %. Carbon steel was selected for tubing material in the early stage of field development. After about 3 years, tubing perforation was caused by serious corrosion. Then carbon steel wasupgrade to 13Cr. However, it was found that there was serious corrosion in the connection part of tubing, and the corrosion was caused by the CO2 and condensate water.

Based on the experience in Yaha gas field, the modified 13Cr tubing was used in the Dina2 gas fields, and the reservoir temperature 140C, pressure 110 MPa, depth 5200 m, and CO2 concentration 0.26-1.02 %. Although the well condition is less harsh, serious corrosion still occurred concentratedly on tubing pin end. Considering premium tubing leak in Dina field happened during acidification operations, and the results of series simulation tests conducted, the understandings were achieved that acid will cause serious corrosion to the inner wall of tubing, aslocal corrosion is dominant factor of stainless steel.

The super 13Cr material was used in Keshen gas field which has reservoir temperature 150-188C, pressure 105-136 MPa, depth 6000-8038 m, and CO2 concentration 0.1-1.1 %. However, tubing fracture happened one by one, which originate from stress corrosion cracking caused by mixture of phosphate packer fluid and killing mud. Therefore, material selection needs to considerthe compatibility of different fluids, and formate was chosen as packer fluid. By December 2020,it has been used in 103 wells of Kuqa foreland basin, abnormal annular pressure is presented in 6 Wells, and the longest service time is six years.

As the rapid exploration and development of Kuqa foreland basin, the proper material selection become more difficult for gas reservoir temperature more than 190C and its pressure greater than 140 MPa, the past practices about material selection may provide the reference, and the story about material selection will be continued.
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

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

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

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

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

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

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

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

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.