bluuebunny/crossref_metadata_2025 huggingface dataset:
The Perspective of Novel Chemical Tracer Technology in Reservoir Surveillance and Hydrodynamic Modelling for More Efficient Hydrocarbon Recovery
Authors: Husein Nadir , Malyavko Evgeny Aleksandrovich , Gazizov Ruslan Rashidovich , Buyanov Anton Vitalyevich , Romanov Aleksey Aleksandrovich , Gilbert Nikolay Andreevich
Published: October 2021

Today, efficient field development cannot be managed without proper surveillance providing oil companies with important geological and engineering information for prompt decision-making. Once continuous production is achieved, it is necessary to maintain a consistently high level of oil recovery. As a rule, a reservoir pressure maintenance system is extensively implemented for this purpose over the entire area because of decreasing reservoir pressure. At the same time, it is important to adjust the water injection to timely prevent water cut increasing in production wells, while maintaining efficient reservoir pressure compensation across the field. That is why it is necessary to have a relevant inter-well hydrodynamic model as well as to quantify the water injection rate. There are many ways to analyse the efficiency of the reservoir pressure maintenance system, but not all of them yield a positive, and most importantly, a reliable result. It is crucial that extensive zonal production surveillance efforts generate a significant economic effect and the information obtained helps boost oil production.

Thus, the main objective of this paper is to identify a method and conduct an effective study to establish the degree of reservoir connectivity and quantify the inter-well parameters of a low permeability tested field.
Green Fluid Technology: How Food Wastes Can Revolutionize the Oil and Gas Industry
Authors: Al-Hameedi Abo Taleb Tuama , Alkinani Husam Hasan , Dunn-Norman Shari
Published: October 2021

Some conventional drilling fluid additives utilized to adjust drilling fluid properties can lead to many issues related to personnel safety and the environment. Thus, there is a need for alternative materials that have less impact on personnel safety and the environment. Many researchers have begun to investigate new alternatives, one example is food wastes. Due to their eco-friendly properties and their vast availability, food wastes are a good candidate that can be exploited as drilling fluid additives. In this work, five different concentrations of eggshells powder (ESP) were added to a reference fluid and the mud weight was measured using mud balance to understand the effects of ESP on mud weight. The results were compared with five concentrations of two commonly used drilling fluid additives - calcium carbonate (CaCO3) and barite. The findings showed that the drilling fluid blends with ESP have significantly outperformed the drilling fluid blends with barite and CaCO3 and for all concentrations in terms of mud weight improvement. The second best blends in terms of mud weight enhancement were the blends with barite and followed by the blends CaCO3. In conclusion, food waste material - ESP outperforming two of the most common drilling fluid additives shows a potential for ESP and other food wastes to be utilized as drilling mud additives in the petroleum industry. This will reduce the harmful chemicals disposed to the environment, reduce exposure risks of drilling crews to harmful chemicals, minimize drilling fluid cost, and revolutionize the industry while contributing to the economy overall.
Practical Upscaling Process for Enhanced Water Alternating Gas : A Numerical Investigation
Authors: Majidaie Saeed , Hendraningrat Luky , Hanifah M Azri Bin
Published: October 2021

Water alternating gas (WAG) is a well-known strategy to improve the mobility issues during gas injection. However, WAG was identified still having some challenges during implementation at oilfield with high reservoir heterogeneity and high permeable zones in the reservoir and will cause unfavorable mobility ratio. Enproperties of the selected core samplehancement of WAG (EWAG) using foam and surfactant has been research to solve its issue and has success stories. This paper will describe the work process of EWAG to be Pilot at Malaysian oilfield, focusing on numerical investigation during upscaling process.

Foam treatment has role for gas mobility control, delaying gas breakthrough and diverting gas to unswept zones. Meanwhile, the surfactant was utilized to reduce the IFT between gas and liquid to enable gas dispersion into liquid phase. An in-house foaming surfactant has been developed and used for coreflooding experiment at harsh environment. It was used to generate stable foam in contact with gas and it caused a mobility reduction which was suitable for mobilizing trapped oil and hence improving oil recovery. Coreflood experiment was performed on native core and all experimental results were consolidated and checked for the quality prior model calibration in the reservoir simulator. Once coreflood model was constructed, base case was run using default foam parameters. It aimed initially to test whether the model run smoothly and to observe the matching quality using the default values. Once satisfactory matchings were achieved, the process continued with foam parameters upscaling. During scale-up process the velocity of the fluids and pressure drop were conserved as laboratory data. The important scale-up parameters and the corresponding scale-up ratio were investigated.

Mobility Reduction Factor (MRF) was calculated by dividing average DP for each foam cycle with base differential pressure (DP) in the prior gas injection. MRF values for both lower and higher rate show increasing MRF values. Regardless, these values are lower in lower flowrates sequences compared to ones for higher flowrates. This corresponds to MRF values calculated in the laboratory analysis. Therefore, stronger and more stabilized foam were generated using higher injection rates. Lower and higher flowrates had distinctive set of foam parameters. The acceptable matches for differential pressure, oil, water, and gas were achieved. for lower flowrate.

Based on this study, model was able to capture production trends depicted in the laboratory analysis. The foam parameter set from higher flowrates have more potential for further upscaling and modeling in full-field scale.
New Digital Well Construction Planning Solution: Improving Efficiency & Quality of Well Design through Collaboration and Automation
Authors: Suryadi Hendrik , Li Haifeng , Medina Diego , Celis Alex
Published: October 2021

Drilling wells with minimum risk and optimizing well placement with the least possible cost are key goals that companies strive to achieve. The major contributor to the successful execution of the well is the quality of the drilling program. Well design is a complex process, which requires full collaboration of multiple domain roles & expertise working together to integrate various well-planning data.

Many design challenges will be encountered, such as risk assessments, domain-specific workflows, geological concerns, technology selections, cost & time estimation, environmental and safety concerns. Design process efficiency depends on effective communication between parties, quickly adapting to any changes, reducing the number of changes, and reducing complicated & manual processes. Current existing workflow and tools are not promoting an excellent collaborative environment among the different roles involved. Engineers utilize multiple engineering applications, which involved many manual data transfers and inputs. The different party is still working in a silo and sharing the design via email or other manual data transfer.

Any changes to the design cause manual rework, leading to inconsistency, incoherency, slow decision & optimization process, and failure to identify all potential risks, increasing the well planning time. The new digital planning solution based on cloud technology allows the design team to maximize the results by giving them access to all the data and science they need in a single, standard system. It's a radical new way of working that gives engineers quicker and better-quality drilling programs by automating repetitive tasks and validation workflows to ensure the entire plan is coherent. This new planning solution allows multiple roles & domain collaboration to break down silos, increase team productivity through tasks assignment, and share all data. An automated trajectory design changes the way engineers design trajectory from manually connecting the path from a surface location to the target reservoir location to automatically calculate & propose multiple options with various KPIs allowing the engineer to select the best trajectory option. The system reinforces drilling program quality through auto engineering analysis, which provides quick feedback for any design changes and provides an integrated workflow from the trajectory design to operational activity planning and AFE.

The automation of repetitive tasks, such as multiple manual inputs, frees domain experts to have more time to focus on creating new engineering insights while still maintaining design traceability to review updates over the life of the projects and see how the design changes have optimized the drilling program. This new solution solves some of the significant challenges in the current well-planning workflow.
Predicting Seismic-Based Anisotropy for Prevent Pre-Drill Risk Using a Novel Type Neural Network
Authors: Ding Yan , Cui Meng , Wang Hai ge , Fei Zhao , Shi Xiao yan , Huang Kai
Published: October 2021

While drilling into fracture zones, lost circulation frequently occurs, resulting in a waste of productive operation severe cases, the well's destruction. However, due to complex development mechanisms and high heterogeneity, identifying and predicting fractures is extremely difficult. This study proposes a new drilling loss prevention idea to evaluate fractured lost circulation risk using seismic and wellbore data by a novel neural network. The approach works in two steps. First, the fracture anisotropy of a lost circulation sample curve is computed and interpreted using well logs. Second, using seismic attributes as constraints, a novel neural network is used to develop a prediction model. The field application in the Sichuan basin verifies the method's efficacy and confirms the method's ability for predicting lost circulation probability both along the well trajectory and in regions away from the drilled wells.
Successful and Efficient Drill & Drive Conductor Operation in Offshore East Java
Authors: Akbar Muhammad Ikhsan , Tobing Jerry , Musa Mohd Zarir Bin , Fajar Irshad , Ardiansyah Fajar
Published: October 2021

Abstracts

Conductor setting depth is critical to provide structural support for next drilling sections. The shoe strength must suffice for drilling ahead and avoid any washout and unstable zone. The objective is to design and run conductor smoothly in regards to engineering and operation aspect.

Multidisciplinary approach including geotechnical, drilling engineering, and structure, was implemented during planning strategy. The pre-determined conductor setting depth was defined on the maximum mud weight to be used during drilling surface hole section in accordance to the formation strength below the conductor with the purpose of not inducing losses to the formation. Lateral distance between conductor and platform jacket pile was also analyzed to secure the jacket integrity. Anti-collision analysis was performed to prevent collision due to the existence of production well in same platform. Conductor pipe size and specification with some feature was defined to withstand under anticipated load and environment. To determine the way to achieve target depth and the suitability of hammer type, drivability analysis was performed with various anticipated condition. Considering shallow refusal depth, drill and drive was required to reduce shaft friction of soil. Another environmental challenge arise during conductor operation was unable to contain fluid and cutting returns from clean-out process causing return to cover part of the production platform facility. Some of technology were planned to mitigate this challenge.

By having comprehensive conductor design, the conductor pipe in all four wells drilled has been successfully installed without any problem on platform jacket integrity and subsequent drilling section. This approach also enabled to efficiency of conductor installation where the number of clean-out and driving run could be reduced. The overflow return challenge could be fully contained by utilizing selfdesigned equipment. The overall operation days of conductor has shown improvement with 1.02 saving days on the last well which equivalent to amount of cost saving around USD 203,500.
Successful Lifting of Oil with High Concentration of Hydrogen Sulfide by Artificial Lift System – Case Study
Authors: Rehman Abid Ur , Abdelbary Marwan
Published: October 2021

Due to the low cost of crude oil, it is highly unusual for the operators to drill exploration wells, for the past few years. Adding that as well to the world's economy collapse due to the pandemic at the start of 2020, it is now more than ever a necessity to use artificial lift methods to lift from previously shut-in wells or maximize current production of the wells, as to grapple with the running expenses of operators.

The artificial lift is a vast field with different lift methods applicable to a single well. Hence, the selection of an optimum lift method is critical. During the worst economic slump, the economic analysis will play a decisive role in the application of an artificial lift system (ALS) along with a technical review. The jet pump system is one of the most reliable artificial lift systems for lifting shut-in wells. The installation time of this system is minimal, and production starts right away. However, the system can prove to be very expensive, if the design is not done critically.

This paper is about lifting a well that was not able to flow naturally. The vertical well B3 located in northern Iraq was drilled in May 2018 to a total depth of 521 meters. But the well was not able to flow naturally, and the jet pump was designed for the well based on well completion, downhole pressures, temperature and reservoir fluid properties. The evaluation and design of the downhole jet pump and surface pumping unit requirements were performed on Jet Pump Evaluation and Modeling Software.

This well produced approximately 1700 BOPD. Since, the well was not flowing before the installation of the jet pump, most of the production data was obtained after deployment of ALS and production was optimized accordingly. The production had a high content of Hydrogen Sulfide as well, which was treated accordingly for safety of personnel, equipment, flow lines and environment. This paper describes the details about the application, optimization and operation of the jet pump system deployed on inactive wells with a high concentration of sour gas.
Understanding the Facies Architecture of a Fluvial-Aeolian of Tensleep Formation Using a Machine Learning Approach
Authors: Hardanto Lilik Tri
Published: October 2021

Many aeolian dune reservoirs are built from various dune types, and many may remain unrecognized in subsurface work. The challenge is to tackle the complex geological architecture of dune types within the Teapot Dome dataset caused by wind and water erosion. Machine Learning (ML) helps predict facies architecture away from boreholes using seismic attributes and facies logs. It provides a detailed understanding of the facies architecture analysis of the relationship between the fluvial–aeolian environment in Tensleep Formation based on seismic and well data. It allows operators to wisely assess their hydrocarbon reservoir, improve safety, and maximize oil and gas production investment.

The data from the Teapot Dome field (Naval Petroleum Reserve No.3 - NPR-3) provides a good testing ground for Machine Learning, as it is easy to validate and prove its value. This study will show how the ML supervised learning method incorporating Neural Network Seismic Inversion (NNSI) can successfully create porosity log and facies volumes. Moreover, unsupervised learning using Multi-Resolution Graph-based clustering (MRGC) can be used to classify the facies logs. NNSI has 0.963 for the cross-correlation coefficients for all wells. The ML approach was used to help recognize the type of aeolian dune reservoirs in the subsurface and correlate the well log and facies volumes. In addition, ML allowed the distinct sequences and reconstruction of their depositional history in the Tensleep Formation. This study also refers briefly to other examples of fluvial-aeolian facies architecture worldwide. It successfully found the ancient model in an existing modern fluvial-aeolian environment, revealing hidden information about facies architecture based on the geometrical shape of geobodies in the oil-producing reservoir in the Tensleep Formation.
Rich-Gas Condensate Huff and Puff Process in High-Volume, Watered-Out, and Highly Viscous Heavy Oil Wells, Case Study in Iraq
Authors: Tang Xueqing , Wang Ruifeng , Cheng Zhongliang , Lu Hui
Published: October 2021

Halfaya field in Iraq contains multiple vertically stacked oil and gas accumulations. The major oil horizons at depth of over 10,000 ft are under primary development. The main technical challenges include downdip heavy oil wells (as low as 14.56 °API) became watered-out and ceased flow due to depleted formation pressure. Heavy crude, with surface viscosities of above 10,000 cp, was too viscous to lift inefficiently. The operator applied high-pressure rich-gas/condensate to re-pressurize the dead wells and resumed production. The technical highlights are below: Laboratory studies confirmed that after condensate (45-52ºAPI) mixed with heavy oil, blended oil viscosity can cut by up to 90%; foamy oil formed to ease its flow to the surface during huff-n-puff process.In-situ gas/condensate injection and gas/condensate-lift can be applied in oil wells penetrating both upper high-pressure rich-gas/condensate zones and lower oil zones. High-pressure gas/condensate injected the oil zone, soaked, and then oil flowed from the annulus to allow large-volume well stream flow with minimal pressure drop. Gas/condensate from upper zones can lift the well stream, without additional artificial lift installation.Injection pressure and gas/condensate rate were optimized through optimal perforation interval and shot density to develop more condensate, e.g. initial condensate rate of 1,000 BOPD, for dilution of heavy oil.For multilateral wells, with several drain holes placed toward the bottom of producing interval, operating under gravity drainage or water coning, if longer injection and soaking process (e.g., 2 to 4 weeks), is adopted to broaden the diluted zone in heavy oil horizon, then additional recovery under better gravity-stabilized vertical (downward) drive and limited water coning can be achieved.

Field data illustrate that this process can revive the dead wells, well production achieved approximately 3,000 BOPD under flowing wellhead pressure of 800 to 900 psig, with oil gain of over 3-fold compared with previous oil rate; water cut reduction from 30% to zero; better blended oil quality handled to medium crude; and saving artificial-lift cost. This process may be widely applied in the similar hydrocarbon reservoirs as a cost-effective technology in Middle East.
Driving Resource Stewardship to Secure Hydrocarbon Resource Development for Sustainability and Growth in Sarawak Region
Authors: Ngan Arthur Cheng Ho , Sinha Ankaj Kumar , Saad Harnee Bt , Jaafar Juhaidi B
Published: October 2021

Strategic vision and long-term view of upstream development plan is one of the key directives entrusted to Malaysia Petroleum Management (MPM) to secure sustainable production for the nation. The Sarawak Area Development Planning (SK ADP) is one such critical study aimed at identifying the inventory of hydrocarbon resources, potential outlook on projects' commercial viability, as well as shaping the portfolio mix strategy to deliver the long-term business growth. This SK ADP study also keeps Petroliam Nasional Berhad (PETRONAS) well-positioned to steer Petroleum Arrangement Contractors (PACs) in developing and maximizing the full value of resources. This includes outlining opportunities to collaborate in project sequencing and cost optimization efforts. This paper illustrates the methodology, process workflow and key takeaways from the SK ADP study.

The SK ADP study was conducted to establish a development blueprint based on overall available resources and projects' first hydrocarbon sequencing for the short-term and long-term development planning in the Sarawak region. The key objective of the study was to identify the most optimum and technically viable integrated development plans, whilst also incorporating the agreed commitments and existing limitations inclusive of technology application and replications. The process workflow consisted of identifying six focus areas to further enhance the Sarawak Portfolio, maximizing the assets' value and ultimately meeting overall supply and demand requirements. These focus areas act as guiding principles to mature the overall development plan for the area, relating to generating an inventory basket, facilities optimization, clustering strategy, technology evaluation, contaminant management and risk assessment. Cross-discipline integration plays a pivotal role in shaping the final roadmap for each of the focus areas coupled with holistic validation.

With the SK ADP in place, it can function as a key reference document and kept updated with the latest developments to maintain PETRONAS' agility in the pursuit of both business sustainability and continuous growth in the region. Key deliverables from this ADP can be turned into actionable insights for field implementation and help boost overall resource management in the region for long-term production delivery. This paper presents the best practices adopted for region level development planning in alignment with strategic vision for business growth.
Breakthrough Enhanced Oil Recovery Technology with Low Cost & Fast Yield on Pilot Test of Vibroseismic EOR Technology in Tempino Field, Sumatera, Indonesia
Authors: Sitompul Victor , Alfian Muhammad , Sitompul Fransiskus Ondihon , Winata Denie , Diharja Tino , Sutadiwiria Gunawan , Paryoto Sumadi , Dusyanto Erwin Dicky , Rahadian Reza , Erwanto Pungki Eka , Triwanto Alip , Sumirat Iik , Alfajri Reza , Ekalaya Muhammad Aji , Nurrakhman Ahmad Ardhy , Asy'ari Husein
Published: October 2021

Enhanced Oil Recovery (EOR) is a tertiary recovery which requires relatively a high cost of CAPEX and OPEX. The current EOR technique is generally stand alone and injected into single reservoir layer without contributing to the other layers (unconnected reservoir layer). For this reason, a breakthrough of low cost EOR technology (CAPEX & OPEX) is needed, especially since oil prices tend to fall low. Vibroseismic EOR is one of the EOR methods (categorized as mechanical EOR) that is inexpensive, fast response / yield, high mobility (can be moved to another place), environmentally friendly, and could be combined with the waterflood method or other EOR methods to get more effective and optimal result. However, the research & implementation on Vibroseismic EOR are still limited. The paper describes the pilot test of Vibroseismic EOR technology in Tempino Field.

The initial stage is to select the suitable field for implementation Vibroseismic EOR. Then, the rock & fluid properties of the selected field are tested and examined by vibration and stimulation in the laboratory to obtain optimum frequency of 20 Hz S waves (circular / transverse) and 35 Hz P waves (longitudinal). The field scale-up process is carried out by measuring or testing field parameters called Vibroseis Field Parameter Test (VFP Test). VFP Test results get the optimum frequency of S and P waves of 20 Hz using 3 trucks and drive level 70% with amplitude value up to 0.024 rms (root mean square). Through the EOR vibroseismic method, the truck is the source of vibrations on the surface will generate acoustic waves propagating through the rock (subsurface) throughout the reservoir layer within the wave penetration range, generally reaching a depth of 6500 ft depending on the amplitude / power source of vibration, thickness of weathered layer, and rock type. The waves that reach the reservoir will affect the rock & fluids properties.

The pilot test results on production wells showed a positive response within 1 month after vibration, especially those around the existing injection wells which the permeability was relatively good. The increased production accumulative of 10 (ten) monitoring production wells about 8% and withhold declining rate up to 20% from base case. Oil drainage around production wells and drainage direction are confirmed by changes in hydrocarbon saturation maps through passive seismic techniques measured before, during, and after vibration.

The results of this pilot test show that Vibroseismic EOR technology is very promising to be developed to the full-scale stage and implemented in other areas.
Novel Simulator for Design and Analysis of Wax Removal Treatment from Well Flow Lines Using Thermochemical Fluids
Authors: Qamruzzaman Mohammed , Chandra Roy Dhirendra , Raman Ravi
Published: October 2021

Treatment of well flow lines with thermochemical/exothermic fluid has shown good results for wax removal compared to conventional hot oil, hot water or solvent treatments. However, the technique has not gained widespread use due to lack sufficient scientific publications that can give more insights over its use and help in designing a safe and effective treatment.

This paper presents a novel transient mathematical model for design and analysis of thermochemical treatment for well flow lines by taking into account the chemical kinetics, heat transfer, fusion of wax and associated two-phase flow. The governing equations have been solved using tools of computational fluid dynamics and heat transfer (CFD - HT). The resulting simulator can be used to prepare an optimum thermochemical plan by analysing the effects of important factors including wax details, deposition profile, heat loss, formulation composition and injection strategy.

Simulation results with the developed model indicate that entire filling of flowline with thermochemical fluid is not necessary for complete wax removal. Injection of a small thermochemical spacer in the flow line followed by its displacement with crude oil can be suffice in case of short flowlines of onshore fields. Selection of initial reactant concentration and pH has to be done judiciously based on the maximum allowed temperature in the flowline and the desired extent of chemical utilization. A sensitivity analysis has shown the existence of an optimum range of injection rate below which wax removal efficiency is compromised by excessive heat loss and above which it is reduced by insufficient residence time. The major limitation of this technique is encountered for large flowlines where a possibility of re-solidification of removed wax deposits exist due to excessive heat loss. Flowlines of length less than 5 km are found to be ideal candidates as in that case, sufficiently high temperatures can be maintained throughout the journey of thermochemical spacer in the flowline which will prevent re-solidification. The simulator has been validated with field implementation results of two well flow lines where the designed jobs have been successful in removing the entire wax deposits as predicted by the simulator.
A Step Change in the Digital Oilfield Arena: Cloud Computing and Workflow Integration for Production Operations Solutions
Authors: Kotiyal Aditya , Prasad Nagaraj Guru , Michael Lester Tugung
Published: October 2021

Digital oilfield applications have been implemented in numerous operating companies to streamline processes and automate workflows to optimize oil and gas production in real-time. These applications are mostly deployed using traditional on-premises systems; where maintenance, accessibility and scalability serves as a major bottleneck for an efficient outcome. In addition to this challenge, the sector still faces limitations in data integration from disparate data sources, liberation of consolidated data for consumption and cross domain workflow orchestration of that data.

The dimensional change brought by digital transformation strategies has paved a path for the Cloud- based solutions, which have recently gained momentum in the oil and gas industry pertaining to their wider accessibility, simpler customization, greater system stability and scalability to support larger amount of data in a performant way.

To address the challenges mentioned earlier, we have embarked on a journey with Production Data Foundation which brings together production and equipment data from across an organization.

In this paper, we will highlight how Production Data Foundation, hosted on the cloud, provides the underlying infrastructure, services, interfaces required to support and unify production data ingestion, workflow orchestration, and through the alignment of the common domain and digital concepts, improve collaboration between people in distinct roles, such as production engineers, reservoir engineers, drilling engineers, deployment engineers, software developers, data scientists, architects, and subject matter experts (SME) working with production operations products and solutions.
Replacement of MEG with KHI for Hydrate Control in Subsea Flowline Offshore Myanmar
Authors: Kim Jonghyun , Scalea Paolo , Hwang Chulhwan , Kim Jeongmoon
Published: October 2021

Objectives/Scope

This paper describes the successful replacement of Mono Ethylene Glycol (MEG) by Kinetic Hydrate Inhibitor (KHI) to guarantee flow assurance in the Shwe field subsea production system, offshore Myanmar. It covers the initial difficulties experienced with MEG, specific field conditions, the comprehensive KHI selection process and testing up to field application and operation.

Methods, Procedures, Process

MEG used for hydrate inhibition in the field's subsea flowline was originally regenerated in the topside facility, however contamination of the MEG with salts from formation water was causing process upsets. The option of installing a reclamation package presented many challenges and, after review of field conditions, the application of a KHI was considered as a promising alternative to MEG. With the engagement of specialist chemical suppliers a broad and challenging series of laboratory, as well as field tests, was carried out to select a suitable product. Finally a dedicated permanent injection skid was installed to guarantee stable KHI delivery and production.

Results, Observations, Conclusions

The difficulties caused by salt contamination of the MEG system, combined with the intricate field logistics at the remote site offshore Myanmar, entailed a speedy solution. This combined with suitable operating parameters of the field; i.e. low water content, high wellhead flowing temperatures, subcooling within known KHI operating range, ensured KHI was an economical solution.

Nevertheless from desktop study to successful field application a series hurdles had to be crossed, including performance and compatibility tests, simulating all the expected Shwe Offshore Platform (SHP) operating conditions: Determination of Hydrate Equilibrium Temperature (HET); Induction Time Autoclave test for the required residence time in the presence of Corrosion Inhibitor (CI); Hot Injection ests at wellhead operating temperature; Thermal stability tests for topsides and condensate disposal system; Umbilical material compatibility tests; Compatibility of KHI with incumbent products (MEG and CI).

Testing of a range of products, carried out by specialist chemical supplier, resulted in the selection of a qualified product, followed by a successful field application testing programme.

Seven years after its introduction, KHI has helped achieve optimum field uptime and reduced operational costs as well as eased logistics constraints.

Novel/Additive Information

KHI is not new to the Oil & Gas industry, however information on its selection and application is not widely available. This paper sheds light on the steps to be considered when evaluating KHI as a suitable hydrate inhibitor, as well as the detailed laboratory tests for proper selection of a product. The intent is to help operators who are facing challenges with hydrate inhibition and could revert to KHI as an alternative.
Maximizing Co-Activity Operation and Mastering Drilling Practice as Effective Strategies for Marginal Field Development
Authors: Hadistira Praja , Yuda Bintang Kusuma , Setiohadi Setiohadi , Yudhatama Muhammad Alfianoor , Wijaya Ryan Aditia , Wiharja Andre , Agriawan Crisa
Published: October 2021

A limited remaining reserve is one of the challenges commonly found in mature field development. Swamp fields in the Mahakam block is an example of mature field development which leads to a marginal operation. Delivering wells more economically is one of the key points to survive during those conditions. Rig operation with a significant daily expenditure could be a way for improvement to yield economic wells.

In general, an efficient rig operation would deliver wells in a shorter duration and at a lower cost. In order to lessen the well duration, two aspects could be improved: performing co-activity operation to shorten the horizontal time (preparation) and mastering drilling practices to shorten the vertical time (drilling). In the co-activity operations aspect, various initiatives have been implemented, such as rigless operations, batch drilling, and offline or simultaneous activities. While in the drilling practices aspect, drilling parameters, bit design, connection practice, and team motivation were the areas that have been improved. This paper will elaborate further on those initiatives.

Implementing massive co-activity operations and the best drilling practices have demonstrated a significant time saving of 24% for the shallow well (final depth around 1800 m) and 27% for the deep well (final depth around 4300 m) in the block. These practices have also made a new record of the fastest well completion in 2.17 days and the highest drilling ROP for 141 m/hour with drilling 2303 m in the first 24 hours. The record of most drilled length in 24 hours is the world best performance of RSS BHA as per Directional Driller Company worldwide record. As a result, the 2020 average cost of the shallow well was 2.6 MUSD while the deep well was 4.1 MUSD.

Those massive co-activity operations and drilling practices have been properly executed since 2019 without any safety incident and related NPT. The positive results have helped the development project to survive in marginal conditions.
Kedung Keris Full Well Stream Pipeline Fiber Optic Leak Detection System
Authors: Chairunissa Cindy , Amanu Deny Kalfarosi , Astari Grizki , Indrayana Eska
Published: October 2021

Kedung Keris (KK) is a sour oil field based in Cepu Block, Indonesia. KK field was originally planned to have a processing facility with separate pipelines to deliver crude & produced water, while the gas was planned to be flared. To reduce cost, this concept was changed to a wellpad with full well stream pipeline with new technology of Fiber Optic Leak Detection Sensing System (LDSS) as a key enabler.

The fiber optic LDSS functions by leveraging fiber optic cable attached to the pipeline to detect leak as well as intrusion to the pipeline's Right-of-Way through real-time analysis of physical characteristics of a leak and intrusion, such as changes in temperature, pressure, ground strain and acoustics.

The implementation of LDSS, together with other safeguards built into the pipeline design, operations and maintenance, allowed the KK Project to eliminate the separation facility at KK wellpad and an additional water pipeline. It also reduces the flaring by billions of standard cubic feet of gas cumulative until end of PSC life as originally all gas planned to be flared. The change of KK Project concept altogether yielded tens of millions of US dollar gross cost savings (~30% of CAPEX + OPEX reduction) following the KK startup in late 2019. The installed LDSS proven to detect leak for up to few meters location accuracy and has intrusion detection capability. KK Project has pioneered the implementation of fiber optic leak detection system for Indonesia oil and gas companies. This work provided further insight to the utilization of such technology in full well stream pipeline where traditional leak detection system implementation will not be acceptable. Consecutively, full well stream pipeline deployment can lead to future CAPEX + OPEX efficiency in facility project design and operation, as well as flaring reduction opportunity.
A Novel Design Method for Optimizing the Diverter Dosage in Hydraulic Fracturing Using Three-Dimensionally Printed Fractures
Authors: Wang Meng , Che Mingguang , Zeng Bo , Song Yi , Jiang Yun , Fan Meng , Wang Yonghui , Wang Xin , Zhu Guangyou , Guo Wei
Published: October 2021

Application of diversion agents in temporarily plugging fracturing of horizontal wells of shale has becoming more and more popular. Nevertheless, the studies on determining the diverter dosage are below adequacy. A novel approach based on laboratory experiments, logging data, rock mechanics tests and fracture simulation was proposed to optimizing the dosage of diversion agents. The optimization model is based on the classic Darcy Law. A pair of 3D-printed rock plates with rugged faces was combined to simulate the coarse hydraulic fractures with the width of 2.0 ~ 7.0 mm. The mixture of the diversion agents and slickwater was dynamically injected to simulate the fracture in Temco fracture conductivity system to mimic the practical treatment to temporarily plugging the fracture. The permeability of the temporary plugging zone in the 3D-printed fractures was measured in order to optimize the dosage of the selected diversion agents. The value of Pnet (also the value of ΔP in Darcy Formula) required for creation of new branched fractures was determined using the Warpinski-Teufel Failure Rules. The hydraulic fractures of target stages were simulated to obtain the widths and heights. The experimental results proved that the selected suite of the diversion agents can temporarily plug the 3D-printed fractures of 2.0 ~ 7.0 mm with blocking pressure up to 15 MPa. The measured permeability of the resulting plugging zones was 0.724 ~ 0.933 D (averaging 0.837 D). The value of Pnet required for creation of branched fractures in shale of WY area (main shale gas payzone of China) was determined as 0.4 ~ 15.6 MPa (averaging 7.9 MPa) which means the natural fractures and/or weak planes with approaching angle less than 70° could be opened to increase the SRV. The typical dosage of the diversion agents used for one stage of the horizontal wells (averaging TVD 3600 m) was calculated as 232 ~ 310 kg. The optimization method was applied to the design job of temporarily plugging fracturing of two shale gas wells. The observed surface pressure rise after injection of diversion agents was 0.6 ~ 11.7 MPa (averaging 4.7 MPa) and the monitored microseismic events of the test stages were 37% more than those of the offset stages.
Optimization of Liquid Accumulation and Gas Injection Duration in Intermitter for Maximizing Production: Case Study
Authors: Ranjan Abhishek , Kumar Rajan , Singh Chandra Shekhar , Lama Tshering
Published: October 2021

Gas lift is the process of injecting gas into the tubing at a predetermined depth in order to lift the crude oil to the surface. Gas lift is applied to a well when the reservoir pressure falls to such a level that it does not produce without application of external energy. There are mainly two types of gas lift which are Continuous and Intermittent gas lift. This paper deals with the theoretical determination of relationship between liquid accumulation and gas injection duration in an intermittent gas lift well and how this knowledge can be combined with the experience of Engineers to maximize the production of a well. In order to find the relationship between the given durations, a simple mathematical approach with the assumption that the gas injection time is independent of liquid accumulation time is followed. We, then apply various tools of mathematics such as the principles of maxima and minima, Leibnitz theorem, definition of the slope of a line etc. to finally prove the interdependence of liquid accumulation and gas injection time at which the well can produce at its maximum capacity. This interdependence is plotted on a separate graph with the given times on two axis. This curve represents the values at which the reservoir inflow is maximised and hence another curve representing the tubing outflow is drawn on the same graph to intersect the former curve at the optimum value of liquid accumulation and gas injection time. The paper also discusses the physical significance of the cases in which the two curves do not intersect and its possible solutions which vary in accordance with the experience of engineers and conditions of well. Our mathematical calculation led to an astonishing result that the interdependence between the two given durations is elegant and can be easily found without the use of computer in a very short interval of time. The result indicated that if a tangent is drawn from a point representing gas injection time to the graph of accumulation height versus time, it touches the graph at the value of liquid accumulation time at which the production of well is maximized. This novel approach to determine the value of time in an intermitter or time cycle controller in an intermittent well can be proved to be a boon for gas lift optimizers who would otherwise spend a large part of the time in setting the value on hit and trial basis. The graphical method can determine the optimum value in a shorter interval of time and with greater accuracy saving companies from extra man-hours and unscientific approach to optimizing any intermittent gas lift well.
Integration of Self Organizing Map and Date Driven Methods to Predict Oil Formation Volume Factor: North Africa Crude Oil Examples
Authors: Alusta Gamal , Algdamsi Hossein , Amtereg Ahmed , Agnia Ammar , Alkouh Ahmed , Kcharem Bacem
Published: October 2021

In this paper we introduce for the first time an innovative approach for deriving Oil Formation Volume Factor (Bo) by mean of artificial intelligence method. In a new proposed application Self-Organizing Map (SOM) technology has been merged with statistical prediction methods integrating in a single step dimensionality reduction, extraction of input data structure pattern and prediction of formation volume factor Bo. The SOM neural network method applies an unsupervised training algorithm combined with back propagation neural network BPNN to subdivide the entire set of PVT input into different patterns identifying a set of data that have something in common and run individual MLFF ANN models for each specific PVT cluster and computing Bo. PVT data for more than two hundred oil samples (total of 804 data points) were collected from the north African region representing different basin and covering a greater geographical area were used in this study. To establish clear Bound on the accuracy of Bo determination several statistical parameters and terminology included in the presentation of the result from SOM-Neural Network solution. the main outcome is the reduction of error obtained by the new proposed competitive Learning Structure integration of SOM and MLFF ANN to less than 1 % compared to other method. however also investigated in this work five independents means of model driven and data driven approach for estimating Bo theses are 1) Optimal Transformations for Multiple Regression as introduced by (McCain, 1998) using alternating conditional expectations (ACE) for selecting multiple regression transformations 2), Genetic programing and heuristic modeling using Symbolic Regression (SR) and cross validation for model automatic tuning 3) Machine learning predictive model (Nearest Neighbor Regression, Kernel Ridge regression, Gaussian Process Regression (GPR), Random Forest Regression (RF), Support Vector Regression (SVM), Decision Tree Regression (DT), Gradient Boosting Machine Regression (GBM), Group modeling data handling (GMDH). Regression Model Accuracy Metrics (Average absolute relative error, R-square), diagnostic plot was used to address the more adequate techniques and model for predicting Bo.
PiNTAR Gas Lift System: Paving the Way for Automated Field Implementation
Authors: Sajjad Farasdaq Muchibbus , Wirawan Alvin Derry , Rachmadi Dharmawan Alfian , Suganda Wingky , Susanto Dany , Gusman Muryadi
Published: October 2021

As oil and gas development in Indonesia is shifting towards offshore environment, automation is essential for reducing operating cost. PHE ONWJ as the biggest oil and gas operator in Indonesia develops an automated field operation for gas lift optimization, called PiNTAR.

PHE ONWJ has been operating gas lift wells for almost 40 years. The biggest challenge is how to efficiently conduct the business operations in offshore environment. The current regular operations (for instance production monitoring) are conducted manually in monthly basis. It is time-consuming and requires long time for trouble shooting.

PiNTAR is designed by PHE ONWJ by integrating smart signal system that can be operated remotely without having to be physically presence at the site. The system is integrated with SCADA sensors, satellite system and fully electronic transmitter that sends production data and related parameters to PHE ONWJ head office to be analyzed 24/7 and mitigated if necessary.

PiNTAR has been implemented on more than 50 wells in PHE ONWJ working areas. PHE ONWJ also provides interactive Graphical User Interface based software for monitoring and production adjustment purposes. Standardization is also performed therefore PiNTAR can be implemented in a wider area, with different gas lift situations.

PiNTAR enables operators to quickly diagnose flow irregularities ranging from adjusting injected Gas Liquid Ratio (GLR) to minimize annular flow, modify choke openings, dynamic reallocation of injected gas from multiple well systems, and also allows the team to comprehend a significant amount of flow characteristics in gas lifted wells as measurements are taken in a very small-time frame, ranging from minutes to seconds. PiNTAR also enables automated production test that enables the construction of real time Gas Lift Performance Curve, which reduces operator workload and enables dynamic gas lift optimization. Implementation of PiNTAR also reduces HSSE risks for rope jumping operations in offshore and increases efficiency of fuel and personnel timing in platform.

The publication presents a success story of gas lift automated optimization using in-house development from PHE ONWJ called PiNTAR. Significant monetary efficiency as well as production increase has been observed during the implementation, encouraging the company to pursue further field automation efforts.