bluuebunny/crossref_metadata_2025 huggingface dataset:
Enhancing Rheological Properties and Reduction of Total Acid Number of a Heavy Crude Oil Using Ethanol and Trona
Authors: Almadhaji Ahmed , Saeed Mohammed , Ibrahim Hitham , Ahmed Anas , Maher Ragaei
Published: October 2021

One of Sudanese fields has a heavy crude oil which has a high Total Acid Number (TAN) and high viscosity, can cause a lot of problems in production operation, transport, and storage facilities. The effect of ethanol dilution on the rheological properties of crude (especially the kinematic viscosity) was studied and presented. Moreover, the consequence of blending Trona (NaHCO3.Na2CO3) with a specified amount of Ethanol in the crude can reduce (TAN) to acceptable limits for solving corrosion and flowability problems. The approach is based on the experiments and laboratory works on the crude's samples after blending with a certain amount of Trona and Ethanol. It depends on the results of apparatuses, that are used to measure the samples, for instance, Calibrated glass capillary viscometer and ASTM D664 titration volume Total Acid Number tester which are employed to get the values of kinematic viscosity and TAN, respectively. The tests are established with crude have kinematic viscosity (187 cst) at temperature 75°C and TAN almost (8.51). While increasing the dosage of Trona at the ambient temperature (38°C) with the certain mass percentage of Ethanol (5%), TAN is decreased from (8.51 to 4.00 mgKOH/g). Also, the kinematic viscosity is declined from (187 cst to 96.75 cst) after increasing the volume of Ethanol at 75°C. These outcomes indicated that Ethanol could reduce Sudanese heavy crude's viscosity, and the Trona could decrease the TAN. This reduction occurred due to Ethanol dilution. The Ethanol molecules disturb the molecular structure of the crude, which forms polar bond within the hydrocarbon chain that leads to lower the friction between molecules of hydrocarbon in the crude. Also, Trona shrinks TAN because the Hydroxide ions (OH+) that founded in Trona neutralize the Hydrogen ions (H−) in Naphthenic acid in Sudanese heavy crude. This study can be summarized in the ability to solve the difficulty of transporting and processing the heavy crude oil in refineries; maintains the quality of the crude while utilizing it with friendly environmental materials and low cost.
Managed-Pressure Cementing in HPHT Well with Very Narrow Operating Pressure Window
Authors: Sanchez David Salinas , Lugo Mario Noguez , Torres Oscar Zamora , Castillo Cuauhtemoc Cruz , Rivera Moises Muñoz , Zertuche Xavier Omar Alviso
Published: October 2021

A 7-in. liner was successfully cemented in the south east region of Mexico at 7530 m MD despite significant pressure and temperature challenges. The entire 1,370-m, 8.5" open hole section needed cement coverage and isolation to test several intervals. The challenge of the ultranarrow working pressure window was overcome by using managed pressure cementing (MPC) along with lost circulation solutions for the cement slurry and spacer.

Due to the narrow pressure window (0.05 g/cc density gradient), mud losses could not be avoided during the cementing job. To limit and manage losses, an MPC placement technique was proposed, in conjunction with using lost circulation fiber technology in the cement slurry and spacer. After addressing the losses and narrow working pressure window, the next main challenge was the extremely high temperature (Bottom hole static temperature of 171°C). Extensive lab testing provided the fluid solution: HT formulations for cement slurry and spacer to maintain stability and rheology for placement and management of equivalent circulating density and set cement properties for long-term zonal isolation.

After the liner was run to bottom, the mud density was homogenized from 1.40 g/cc to 1.30 g/cc (pore pressure: 1.38 g/cc). During this process, 32.5 m3 of mud was lost to the formation. During the previous circulation, the backpressure required to maintain the equivalent circulation density (ECD) above pore pressure, which was calculated and validated resulting in 1,100 psi annulus surface pressure (close to the limit of the equipment capacity) during the stopping time. The cementing job was pumped flawlessly with only 10 m3 of mud loss at the end of the job. During reverse circulation, contaminated spacer at surface indicated no cementing fluid had been lost to the formation and adequate open-hole coverage. The liner was successfully pressure tested to 4,500 psi, and cement logs showed that the cement had covered the open hole completely.

MPC is not a conventional cementing technique. After the successful result on this job and subsequent operations, this technique is now being adopted to optimize cementing in even deeper wells in Mexico, where losses during cementing operations in the past had modified or limited the whole well construction and designed completion, and production of the well.
Journey of Effectively Using Real-Time Production Surveillance Tool in Digital Transformation and Well, Reservoir and Facility Management Improvements
Authors: Sahu Sambit Kumar , Lauwerys Christophe , Abdullah Zulfikri , Muhammad Mariana Jamil , Agrawal Divya
Published: October 2021

In 2014, SPE-167857-MS was published highlighting how Real-Time Surveillance using the Shell proprietary Production Universe (PU) application helped to reduce deferment, improve production allocation, optimize test unit capacity, and track well operating envelope in Brunei Shell Petroleum BSP (company) operations in South East Asia.

Since then, there has been significant progress in the application of PU to help the company meet Wells Reservoir Management (WRFM) requirements and Operational Excellence standards in areas such as Platform Production Reconciliation, Well Modeling, Production Estimation, and Exception based Surveillance helping the company to improve their Hydrocarbon and Energy Accounting. The wider introduction of the PU application in the allocation process significantly helped in Hydrocarbon Accounting (HCA), helping company's journey in moving from monthly to daily allocation and assisting to improve the field reconciliation factor (RF).

The utilization of PU has also facilitated real-time monitoring of production parameters supporting engineers to safely and efficiently operate their wells within the Operating Envelopes while adhering to reservoir management guidelines.

The optimization engine of the PU has been used to maximize the production of company contributing to two major success stories of Real-Time Condensate Optimization in a Gas-Constraint system and Gas Lift Optimization in a platform with limited lift gas availability amongst the producing wells.

An Integrated Production Monitoring and Optimization System (IPMOS) provides asset-wide advice on optimally producing company's well within the constraints imposed by limitations on pipeline capacity, compressor throughput, and remote operability while satisfying customer demands.

PU is additionally being used in Proactive Technical Monitoring (PTM) of rotating equipment to identify the critical parameters operating outside the set limits in an exception-based format.

PU alerts & alarms have been configured in a wide range of operational monitoring such as Ensure Safe Production (ESP), Chemical Injection, Annulus Pressure Monitoring(APM), Control-Line pressure, Erosion-Corrosion Monitoring System(ECMS) to alert Production Engineers in case of any discrepancy or exception-based format for them to take remedial actions.

This paper will explain how each of the above applications in PU has helped company in its journey of closing its gap to potential and achieving the digital transformation of its operations.
Bi-Directional Long Short-Term Memory Variational Autoencoder for Real-Time Bit-Wear Estimation
Authors: Luu Trieu Phat , Bomidi John A.R. , Magana-Mora Arturo , Alalsayednassir Alawi , Zhan Guodong David
Published: October 2021

Drilling operations rely on learned expertise in monitoring the drilling performance data and the rock data to assess the dull condition of the drill bit. While human learning can subjectively pick up the indicators based on rig surface data streams, this information is highly convoluted with changes in rock and drilling data. Recent approaches for bit wear estimation also include model-based and traditional supervised machine learning methods, which are usually costly and time-consuming. In this study, we developed a bi-directional long short-term memory-based variational autoencoder (biLSTM-VAE) to project raw drilling data into a latent space in which the real-time bit-wear can be estimated. The proposed deep neural network was trained in an unsupervised manner, and the bit-wear estimation is demonstrated as an end-to-end process.
3D Extended Finite Element Modeling of Hydraulic Fracturing Design and Operation in Shale Gas Reservoir and Validation with Micro-Seismicity Data
Authors: Musa Ikhwanul Hafizi , Leem Junghun , Tan Chee Phuat , Che Yusoff M Fakharuddin
Published: October 2021

Hydraulic fracturing is vital in unconventional shale gas development in order to produce economically from the reservoir. An optimum hydraulic fracturing design and operation can be the key difference between good and poor producing well and economics of the well. One of the most common hydraulic fracturing designs is ball drop system. Using ABAQUS software with XFEM method, a three layers model is used to represent overburden formation, shale gas formation and underburden formation. Rock properties, pore pressure and stress data are used as inputs for the generated model. A horizontal well is created in the middle shale gas formation with three fracture stages and 100m perforation spacing between them. Each hydraulic fracture stage is pressurized sequentially based on the treatment plan of ball drop sliding sleeve completion. The simulated hydraulic fractures are evaluated and compared with the measured field data. The comparison of the average wellbore pressure is good as they all showed within 10% of the measured data. The comparison of the hydraulic fracture geometry with the micro-seismicity data is reasonable overall in view of the data evaluation showing considerable uncertainties in the data. The hydraulic fracturing results also show that at 100m perforation spacing and using sequential hydraulic fracturing method (such as ball drop system), the effect of stress shadow is minimal and does not inhibit the fractures growth. However, the stress shadow effect is found to be pronounced for closer spacing between hydraulic fractures. For future application of the developed XFEM hydraulic fracturing model, it can be utilized to design new hydraulic fracturing completion in order to recommend the optimum completion, including perforation spacing, of development wells in unconventional shale gas field.
First Success of Marine Shale Gas in Ordos Basin: A Review of Recent Exploration Breakthrough in Ordovician Wulalike Formation
Authors: Fu Suotang , Xi Shengli , Yu Jian , Hu Xifeng , Liu Yuan , Zhang Jie , Cai Liang , Li Shenzhuan , Zhao Xianran , Wu Jinlong , Guo Hongzhi
Published: October 2021

Ordos basin in central China is well known for its rich accumulation of natural resources, including Triassic tight oil and Permian tight gas. A recent exploration breakthrough shows that Ordovician shale in the same basin is also promising. The purpose of this study is to capture the engineering details of two horizontal exploration wells exploration in Wulalike formation, which mark the first production of marine shale gas in Ordos basin.

The Ordovician Wulalike formation in the Ordos basin was previously seen as source rock. During early exploration in the 2010s, the formation was found to be gas bearing. However, the Wulalike shale formation shows very different features compared to the Triassic lacustrine shale in the same basin and the Silurian marine shale from Sichuan. The abundance of natural fissures, the low reservoir pressure, and the tendency to produce water are unique challenges and concerns for the Wulalike shale formation.

Based on the pilot well evaluations, two horizontal wells were drilled and completed in the Wulalike formation in different locations in the western Ordos basin in 2019–2020. Both wells were well-landed in the target zone and were completed with multistage large-scale fracturing treatments. Following the well completions, flowback and production tests lasted for 3 to 5 months. Production tests showed that well 1 reached an economically acceptable gas rate in natural flow for a long-term period, producing 20,000 to 60,000 std m3/d, and well 2 produced good gas in the early period but was soon overwhelmed by massive water production. Both wells were evaluated with production logging tools. In well 1, fiber-optic distributed acoustic sensing (DAS) and distributed temperature sensing (DTS) were used, and in well 2, a production logging tool (PLT) was used.

The positive gas production from both wells marks the first production of marine shale gas in the Ordos basin. The understanding of the geology and reservoir, the use of unconventional fracturing and completion practices, the assistance of energized fluid, and post-treatment artificial lift are the technologies that helped achieve this success. Further study is needed on the complexity of the natural fissures to lower the risk of unwanted water production from the Wulalike rocks.

The first successful production from the Wulalike is very critical for the exploration of the Ordovician section in the Ordos basin because it helps to confirm a favorable exploration and appraisal area of 2000 to 3000 km2, which has the potential to turn into a huge reserve. This case study provides value from a technical standpoint, as very few success stories have been reported from low-pressure shale gas previously in China or worldwide.
Non Selective Shallow Unconsolidated Well Re-Entry: Case Study in Mahakam Delta
Authors: Abidiy Izzad , Bawono Yolani , Rizky R. Aulia Muhammad , Pradityo Rico , Rachman Ramadhani , Thalib Hanif , Jamal Muhammad Nadrul , Kusuma Rahadyan , Sobirin Muhammad , Yunus Fata
Published: October 2021

Declining of shallow reservoir reserve urges efficiency effort to switching well architecture from zone-selective gravel pack completion to non-selective tubingless completion. However, zone management in tubingless completion is not as simple as sliding sleeve manipulation in gravel pack well. It requires proper zone isolation of closed zone such as setting plug, tubing patch, or squeezed cement. Therefore, optimum zone management need to be identified to be consistent with cost efficiency effort.

Study in determining optimum zone management captured two nearly identic case of 3 zones of selective well and non-selective well. The well cost, production, and its net present value was compared to evaluate how the reservoir production is managed.

Although selective well has higher initial well cost, but operation cost during the production is significantly low. On the other hand, even non-selective well has lower initial well cost, due to complication on zone management, non-selective well has higher operation cost. The total cost of problematic non-selective well could nearly reach the selective well cost. The complication is identified as downward movement, i.e. re-accessing previously isolated lower zone and isolating upper zone at once. However, this study suggests that strictly following bottom-up production strategy could potentially avoid the complication by 23% more efficient in production and cost index.

Well cost efficiency is not only determined by lower initial well cost. All operating cost during production must be also considered. Optimum well management for both type of completion is a key parameter in order to control the cost efficiency effort. Therefore, well completion design selection must consider not only the cost and production, but also the operation excellence and capability during managing well production in its lifetime.
Optimised Chemical Management for Ichthys Offshore Gas Production
Authors: Lehmann Marc , Brunt Steven , Wyper John , Jewson Barry , Lamba Gaganjot , Mcphee Glen , Anand Jas , Macgregor Bruce
Published: October 2021

The Ichthys Field is located approximately 220 km north-west of the coast of mainland Western Australia and 820 km south-west of Darwin. Gas from the Ichthys Field undergoes processing on an offshore central processing facility (CPF) to dehydrate the gas and remove a Rich MEG phase and condensate. The dry gas is compressed and sent to Darwin via a gas export pipeline while the condensate and MEG are pumped to an interlinked floating production, storage, and offtake facility (FPSO) with hydrocarbon processing capabilities. The FPSO also features the world's largest offshore MEG regeneration system. An integrated chemical supply chain has been developed to deliver bulk chemicals from the vendor chemical supply base in Darwin to the offshore facilities. Delivery is facilitated by specially designed platform supply vessels (PSV) that carry bulk chemicals in dedicated storage tanks and transferred to the offshore facilities using bulk transfer hoses. This paper details aspects of the chemical supply chain and describes best practices that have been developed to manage the safe delivery of bulk chemicals from the chemical supplier to the operator.
Integrated Workflow with Experimentation, Modeling, and Field Implementation Framework Enhances Fracture Diversion Understanding in Carbonate Reservoirs
Authors: Khan Abdul Muqtadir , Usova Zinaida , Yudin Alexey
Published: October 2021

Multiple near-wellbore diverters and their applications exist in the industry. However, understanding of their effectiveness in carbonate acid fracturing applications still has unanswered questions, mainly due to the lack of knowledge on how the fracture width develops at entry points with continuous acid dissolution. This continuum needs to be understood through integrated modeling and experimentation at the yard-scale, and field-scale perspectives.

An advanced numerical model was used to analyze the width development in varying calcite/dolomite fractions and acid concentrations. A robust diversion pill was developed during extensive testing, and its performance was validated in the laboratory using a slot test. The goal was to create a system with reliable bridging ability and low permeability to ensure isolation. Multimodal particles help to ensure effective bridging and plug stability. A similar bridging test was conducted at the yard scale with a small pump and low-pressure line setup leading to an 8-mm inside diameter pipe. Results from the laboratory were validated in the yard test to see parameters affecting the bridging. Finally, a well-specific robust workflow was constructed for diversion pill design.

Modeling done on a high-resolution fracture hydrodynamics and in-situ kinetics model showed that width development in different scenarios varied from 1.5 to 3.0 mm. Laboratory testing was performed in 0.31- to 063-inch width rectangular slots to normalize the flow rate/area of the cross section, and the plug experienced pressure up to 1,200 psi for several hours at temperatures from 115 to 205°F. No extrusion was observed during the test, which is a valid indicator of plug stability. Sensitivity to flow conditions and carrier fluid properties were estimated. The diversion slurry was mixed in a 0.5 wt% solution of guar gum and displaced at pump rates 100 to 999 ml/min. A yard test was designed to see the bridging of the pill at various concentrations of 75 to 300 lbm/1,000 gal and rates of 0.5 to 3 gal/min. All the laboratory- and yard-scale experimental findings were combined with theoretical fundamentals to understand fracture bridging for dynamic diversion applications. A workflow using modeling and advanced volumetrics design was devised to enhance the diversion success in field applications. This led to formulating a parametric design measure β, which showed direct correlation and effectiveness on the diversion process based on synthetic simulations.

This study gives a 360° solution-based understanding of diversion physics. The proposed combination of mechanical and chemical diversion is a cost-effective method for multistage fracturing. Current comprehensive research involving digitized cores and advanced modeling has significant potential to make this a reliable method to develop tight carbonate formations around the globe.
An Unsupervised Learning Model for Pipe Stuck Predictions Using a Long Short-Term Memory Autoencoder Architecture
Authors: Nakagawa Yujin , Inoue Tomoya , Bilen Hakan , Mopuri Konda R. , Miyoshi Keisuke , Abe3 Shungo , Wada Ryota , Kuroda Kouhei , Tamamura Hitoshi
Published: October 2021

Pipe-sticking during drilling operations causes severe difficulties, including economic losses and safety issues. Therefore, stuck-pipe predictions are an important tool to preempt this problem and avoid the aforementioned troubles. In this study, we have developed a prediction technique based on artificial intelligence, in collaboration with industry, the government, and academia. This technique was an unsupervised learning model built using an encoder-decoder, long short-term memory architecture. The model was trained with the time series data of normal drilling operations and based on an important hypothesis: reconstruction errors between observed and predicted values are higher around the time of pipe sticking than during normal drilling operations. The trained model was then applied to 34 actual stuck-pipe events, where it was found that reconstruction errors increased prior to the pipe sticking in some cases (thereby partly confirming our hypothesis) and were sensitive to large variations in the drilling parameters.
Offshore MMV Planning for Sustainability of CO2 Storage in a Depleted Carbonate Reservoir, Malaysia
Authors: Tiwari Pankaj Kumar , Das Debasis Priyadarshan , Patil Parimal Arjun , Chidambaram Prasanna , Low Zoann , Chandran Prasanna Kumar , Abdul Hamid M Khaidhir , Tewari Raj Deo
Published: October 2021

CO2 sequestration is a process for eternity with a possibility of zero-degree failure. Monitoring, Measurement and Verification (MMV) planning of CO2 sequestration is crucial along with geological site selection, transportation and injection process. Several geological formations have been evaluated in the past for potential storage site which divulges the containment capacity of identified large, depleted gas reservoirs as well as long term conformance.

Offshore environment makes MMV plan challenging and demands rigorous integration of monitoring technologies to optimize project economic and involved logistics. The role of MMV is critical for sustainability of the CO2 storage project as it ensures that injected CO2 in the reservoir is intact and safely stored for hundreds of years post-injection. Field specific MMV technologies for CO2 plume migration with proactive approach were identified after exercising pre-defined screening criteria.

Marine CO2 dispersion study is carried out to confirm the impact of any potential leakage along existing wells and faults, and to understand the CO2 behavior in marine environment in the event of leakage. Study incorporates integration of G&G subsurface and Meta-Ocean & Environment data along with other leakage character information. Multi-Fiber Optic Sensors System (M-FOSS) to be installed in injector wells for monitoring well & reservoir integrity, overburden integrity and monitoring of early CO2 plume migration by acquiring & analyzing the distributed sensing data (DTS/DPS/DAS/DSS).

Based on 3D couple modeling, a maximum injection rate of approximately 200 MMscfd of permeate stream produced from a high CO2 contaminated gas field can be achieved. Injectivity studies indicate that over 100 MMSCFD of CO2 injection rates into depleted gas reservoir is possible from a single injector. Injectivity results are integrated with dynamic simulation to determine number and location of injector wells. 3D DAS-VSP simulation results show that a subsurface coverage of approximately 3 km2 per well is achievable, which along with simulated CO2 plume extent help to determine the number of wells required to get maximum monitoring coverage for the MMV planning. As planned injector wells are field centric and storage site area is large, DAS-VSP find limited coverage to monitor the CO2 plume. To overcome this challenge, requirement of surface seismic acquisition survey is recommended for full field monitoring.

An integrated MMV plan is designed for cost-effective long-term offshore monitoring of CO2 plume migration. The present study discusses the impacting parameters which make the whole process environmentally sustainable, economically viable and adhering to national and international regulations.
Enhancing Economics of Resources Development of Mature Mahakam Fields Through Innovation, Design Optimization, and Value Engineering
Authors: Widyoko Bhayu , Indrayana Patria , Hutabarat Toto , Budiarko Andriadi , Siboro Mitterank , Herwin Henricus
Published: October 2021

Mahakam Contract Area is located in East Kalimantan Province, Indonesia. It covers an operating area of 3,266 km2, and consists of 7 producing fields. Most of Mahakam hydrocarbon accumulations are located below body of water, with wellhead production facilities installed in the estuary of Mahakam river (referred as swamp area, 0 to 5m water depth) and the western part of Makassar Strait (referred as offshore area, 30 to 70 m water depth).

Mahakam production history goes as far back as mid 1970s with production of Handil and Bekapai oil fields. Gas production started by the decade of 1990s along with emergence of LNG trading, supplying Bontang LNG plant, through production of 2 giant gas fields: Tunu and Peciko, and smaller Tambora field. In the mid 2000s, Mahakam attained its peak gas production in the level of 2,600 MMscfd and was Indonesia's biggest gas producer. Two remaining gas discoveries, Sisi Nubi and South Mahakam, were put in production respectively in 2007 and 2012. Due to absence of new discoveries and new fields brought into production, Mahakam production has entered decline phase since 2010, and by end of 2020, after 46 years of production, the production is in the level of 600 MMscfd.

In 2018, along with the expiration of Mahakam production sharing contract, Pertamina Hulu Mahakam (PHM), a subsidiary of Indonesian national energy company, Pertamina, was awarded operatorship of Mahakam Block. This paper describes the efforts undertaken by PHM to fight production decline and rejuvenate development portfolio, with focus on expanding subsurface development portfolio and reserves renewal by optimizing development concept and cost through fit-for-purpose design, innovation, and full cycle value engineering.
Enhancing Drilling Response and Improving ROP on PDC Bits by Utilizing 1-in. Diameter Cutters
Authors: Thomas Adam Xavier , Bailey Michael James , Doudou Sofiane , Pérez García Javier , Al Bahri Salim , Al Kiyumi Mohammed , Al Mamari Mohammed , Al Omairi Zahir , Hermawan Aditia , Andoni Bastian
Published: October 2021

This paper details the improvements to drilling performance and torsional response of fixed cutter bits when changing from a conventional 19-mm cutter diameter configuration to 25-mm cutter diameters for similar blade counts in two different hole sizes. Key performance metrics include rate of penetration (ROP), rerun-ability, torsional response, and ability to maintain tool-face control during directional drilling.

A high-performance drilling application was selected with several existing offset wells using a 12¼-in., five-bladed, 19-mm (519) drill bit design, and a concept bit developed using 25-mm diameter cutters while maintaining comparable ancillary features. This was tested in the same field on both vertical and S-shape sections using the same bent-housing motor assembly and drilling performance compared to the existing offsets. A 17½-in. hole size application that experiences high drillstring vibration was also selected, and a 25-mm cutter diameter drill bit was designed with comparable ancillary features to replace a six-bladed, 19-mm (619) drill bit. This was tested in the same field with the drilling performance, and vibration propensity was assessed.

Initial testing in the 12¼-in. section showed extremely promising initial results, breaking the field ROP record in a well-established field of more than 3,000 wells. The rerun of the same bit without repair placed fourth in the field in terms of ROP records. Additional testing in the vertical and s-shape sections showed the new 25-mm cutter diameter design consistently exceeding the ROP performance of the 519 drill bit design while achieving directional targets without any reported drilling concerns. Subsequent trials with other operators saw similar performance improvement with multiple instances of breaking field ROP records.

The first trial of the new 17½-in. hole size design with 25-mm diameter cutters had 34% average higher ROP than the offset average ROP, achieving the field ROP record. An overall 70% improvement during trials was seen in ROP versus the existing 619 drill bit design. The daily drilling reports and client feedback reported a significantly reduced level of drillstring vibration versus offset wells.

This paper demonstrates the potential for a paradigm shift in drilling response and overall ROP by using 25-mm diameter cutters on fixed cutter bits. When correctly modeled, designed, and selected for specific applications, they benefit operators by reducing the time it takes to drill the section, improving repairability, reducing the time that an openhole is left exposed, and reducing drilling costs.
An Outright Success in Oil and Gas Production Arise from Surface Facility Modification – Story of Ujung Pangkah Field
Authors: Eviany Ameria , Ramadhani Ifani , Mario Cio , Nugrahanto Anang , Pramana Harris , Murtani Anom Seto
Published: October 2021

The two most common challenges on the oil and gas production today are the flowing production under natural pressure depletion and the surface facility capacity limitation. Ujung Pangkah field is no exception regarding finding a method to overcome this problem. It compelled to embolden many strategies to ensure the continuity of oil and gas production. Production enhancement initiatives were delivered through both Subsurface and Surface sides.

SAKA Energi Indonesia, as the operator of Pangkah PSC, proved that Surface Modification approach increased the oil and gas production. Historically, gas lift injection dependency in all production wells force a continuous operation of Gas Lift Compressor (GLC) unit to supply gas lift. However, GLC as a production backbone is no longer sustainable, it has reached its maximum limit and unable to fulfil the gas lift rate requirement for all wells. Furthermore, the changing flowing conditions – low gas feeding - from wells are relatable to most of the critical surface equipment.

Considering all the challenges faced in Ujung Pangkah field, SAKA developed initiatives on MP Compressor and GLC configuration by performing compressors restaging. The equipment modifications started out with restaging the MP Compressor (MPC) that led to MP Separator operating pressure reduction – from 22 barg down to 16 barg. Pressure changes on MP Separator also directly affected the GLC system since it works on the same pipeline header. Technical assessment analysis for other corresponding equipment were performed to verify if each of the equipment's operating boundary could accommodate lower pressure at the facility.

Compressor restaging has direct and indirect impacts. The direct impacts are decrease in suction pressure, increase in gas lift rates, and decrease in flowing of suction pressure due to the pressure at wellhead. The indirect impact is production gain from wells by lowering the wellhead pressure. Particularly in the pressure depletion case, this initiative could extend the lifetime of the wells. Production gain was quantified after compressor restaging and pressure system lower to 16 barg. The gain from this method was 3 MMscfd and ~400 BOPD.
A New Standard Design of Lightning Protection System for Offshore and Nearshore Oil and Gas at Tropic Area
Authors: Bahroinuddin Mukhtarus , Anwar Rosihan
Published: October 2021

Based on NFPA-780, offshore platforms, which made from metal framework of a structure are thought of as "grounded" to the ocean and therefore are not needed to be installed external Lightning Protection System (LPS). PHE ONWJ which located at offshore tropic area has implemented NFPA 80 but still experience lightning hit. It generated fire at vent stack andcause operations interference. So that, the objective of this study is to redesign LPS for tropic area. Firstly, the methodology for this study was conducting literature review from previous researches for lightning protection system at tropic area and researches which underlyingNFPA-780. The literature reviews were focusing on lightning characteristic for tropic area andthe lightning density data from local lighting strike monitors surrounding PHE ONWJ. The result of literature reviews would be the basis of lightning strike event reviews in PHE ONWJ facilities. Subsequently, the authors conducted the equipment layout review using rolling sphere method based on previous lightning strike location. Lastly, Authors proposed the recommendationsfor typical LPS for oil and gas at tropic area. Based on literature reviews,lightning characteristic at tropic area has peak strike current twice the sub-tropic and longer "tail" so that the charge current is larger. Larger the charge current of lightning cause greaterimpact into metal structure that is metal melting. Based on NFPA 780/2011, the offshore platform, which is made by metal, and vessel with minimum thickness 4.8 mm are self-protected. However, based on calculation, with the characteristic of lightning at tropic area, the recommendedminimum vessel thickness is 10 mm. This calculation reinforces the fact that standard of Lightning Protection System in NFPA 780/2011 is not sufficient to be applied in tropic area like Indonesia. After calculating the tropic lightning strike range using rolling sphere method, it isrecommended to redesign lightning protection system for some locations at offshore platform and near shore facilities of PHE ONWJ.The lightning protections system locations and quantities are depending on the area and the needed protected equipment in it.The installation isincluding extended mast terminal, free standing mast, low inductive Double Shielded Down Conductor(DSDC), Lightning Event Counter (LEC), and good grounding system at the platform.
A Dynamic Simulation Assessment for Relocating Flare System into Separated Platform Utilizing Idle Subsea Main Oil line
Authors: Winanto Winanto , Bahroinuddin Mukhtarus , Cahyono Endro , Thaliharjanti Margaretha
Published: October 2021

KLB is an offshore platform that consists of production wells and two train gas lift compressors. During well intervention, the KLB operation team must turn off the flaring system due to potential flare radiation of more than 500 BTU/hr-ft2at the working area and gas dispersion more than 50 %-LEL at the flare tip. The relocation of the KLB flaring system to the nearest platform keeps the KLB gas lift compressor operating during this activity. The relocation scenario can maintain the KLB platform production of 700 BOPD.

KLA Flowstation is the nearest platform to the KLB. It is separated one kilometer, connected by an idle subsea oil pipeline, but there are no pigging facilities due to limited space at the KLB platform. Therefore, the comprehensive assessment to relocate the KLB flaring system is a) Flare system study using Flare Network software to simulate backpressure and Mach Number at tailpipe in the KLA and KLB flaring system; b). Dynamic transient simulation using Flow Assurance Software to calculate backpressure, liquid hold up, and slugging condition in the flare KO drum; and c). Flare radiation and dispersion study.

The initial condition of the idle subsea oil pipeline was full of liquid as the preservation for a pipeline to prevent a further oil spill in case of a leak during the idle condition. The dewatering process for the idle subsea pipeline has been conducted by purging the pipeline utilizes 0.7 MMscfd gas lift with a pressure of 100 psig to displace liquid content to 20 bbl. The transient simulation for gas swapping was conducted at a gas rate of 4.1 MMscfd as the train compressor's flaring condition. The calculated backpressure at the KLB safety valve is 12.3 psig below the required maximum of 30 psig. The calculated liquid surge volume in the Flare KO drum during flaring is 17 bbl and can be handled by surge volume inside the KO drum. The predicted condensation inside the subsea pipeline shows that the maximum operation of the flaring system is limited to 30 days. The radiation and gas dispersion to the nearest facility is within a safe limit.

The KLB teams successfully conducted the relocation of the flaring system from the KLB platform to the KLA platform. The result was no interruption of production, no risk of radiation, and no potential explosion during a well intervention. Experience in the last two activities has confirmed that this method can prevent revenue loss of 19 billion rupiahs. This study has initiated a new engineering standard and best practice for flaring systems as opposed to the current practice which states that the flare location shall be at the same location as the production facilities with no pocket piping in between. This study and field experience have proved that the flaring system can be located on a different platform by conducting engineering assessments to ensure process and process safety criteria are within Company and International Standard.
Optimisation of Well and Layer Selection for Re-fracturing
Authors: Zhu Qi
Published: October 2021

In initial fracturing of tight oil and gas reservoirs, due to the influence of geological and technological factors, the fracture conductivity has decreased, and the single-well productivity has been reduced. It is urgent to repeat transformation to restore or increase productivity. Well selection and layer selection is one of the key factors that affect the design of re-fracturing and the effect of stimulation.

Based on a big database of well-sites, establishing machine intelligence theory determines the elasto-plasticity, permeability, porosity, completion parameters, production decline parameters and skin coefficient that affect the effect of re-fracturing stimulation by dimensionless parameter method of well and layer selection and its stimulation evaluation model.

Combined with artificial neural network and BP algorithm, the index weights of strata with different reservoir physical properties are calculated to analyze the final evaluation value of fracturing effect. On the basis of remaining oil distribution research, scale extended fracture repeated fracturing is increased, injection-production well pattern is improved, scale repeated fracturing effect is increased, well pattern is improved, target layer is repeatedly fractured, and oil increase effect is obvious after fracturing.
Embarking on a New Philosophy: Sand Control Design and Exclusion Method for a Field in Peninsular Malaysia, Best Practices and Lessons Learned for Future Development
Authors: M Zain Siti Nur Mahirah , M Zamani Nur Hidayah , Magna Bela Sunanda , AL Selladurai Jagaan , Hashim Saharul , Rosdi Mohd Hisyam , Ramirez Cristian , Tham Dennis
Published: October 2021

Field D is a massive oil-producing field, which consists of more than 15 blocks that have been developed since 1996. All types of completion methods, from openhole stand-alone screens and cased-hole circulating packs to frac packs, have been applied to help maximize field productivity while keeping sand issues to an acceptable level. However, some wells have begun to encounter sand issues, causing a drop in productivity and in some cases become shut-in because of sand accumulation in the tubing. Small fines (<40 micron) are particularly prominent in the produced sand based on samples collected. A field development revisiting campaign was launched to target new drainage points and recover attic oil using existing slots to sidetrack to the targeted zone and install a new downhole sand control completion. The preferred treatment method is an extension pack (EP) after considering reservoir characteristics, namely close proximity to a coal layer, low permeability, and small fines production, among others. These challenges were addressed by combining the oriented perforation design and optimal sand control completion system using a single-trip multizone system, enhanced single-trip multizone system, and a stack pack with a properly designed proppant pumping strategy using xanthan carrier fluid, a fines-control acid system, and 20/40-mesh ceramic proppant with a 10-gauge wire-wrapped screen. Numerous sand control software simulations were performed to achieve tip screenout (TSO) and a sufficient pack factor while addressing all of the wellbore conditions. For the first time in this field, conductivity enhancer material was applied by dry coating it to proppant on-the-fly with the goal of controlling fines migration through the proppant pack, thus increasing porosity and leading to long-term conductivity. The process design, execution, minifrac analysis, and post-job matching for the frac pack treatment are discussed, which lead to the wells producing sand-free at higher than expected reserves and flow rates. Best practices and lessons learned from this campaign can be further used for new upcoming campaigns.
Pushing the Boundaries Through Successful Delivery of Highly Challenging ERD Well in Offshore East Java, Indonesia
Authors: Musa Mohd Zarir Bin , Tobing Jerry , Akbar Muhammad Ikhsan , Fajar Irshad , Nurrakhmadi Wienarno , Muttaqin Hamdan Yudanto
Published: October 2021

With the far-reaching reservoir target coupled with other surface constraint including fix well slot coordinate and pre-determined conductor size, the longest well with 2.5 ERD Index in Offshore East Java was pioneered. The team has big task in hand to ensure all aspect of ERD well engineering and construction are being addressed properly within the fast-paced time frame given. One of the approaches strategized by the team is to split the high angle big hole size long interval of middle section into two casing string which was not the common architecture applied in the other offset wells. The objective was to ensure that the middle section of the well will not be compromised and avoid complication in the deeper section of the well. Worth to mention that the middle section consists combination of challenging lithology that deserve the right solution to avoid unwanted problem. There are highly kartsitified carbonate formation, shale and sand interbedded formation, and thick time dependent shale formation.

To mitigate the challenges previously mentioned, intermediate section which is normally drilled and isolated with 17-1/2" hole × 13-3/8" casing in previous wells, now separated into two sections which require enlargement: 17-1/2" to 20" and 14-3/4" to 17-1/2". This paper focuses on 14-3/4" × 17-1/2" which is the most challenging underreaming operation in this well and the first of its kind in this field application.

Adding to the fact that the inclination reach 75 degree in this section, SOBM and RSS BHA are deployed to mitigate the torque and drag issue. State of the art modelling tool is also used by team to define effectively match BHA and drilling parameter with minimal lateral vibration and stick slip for this section Apart from drilling stage, the enlarged hole size requires a condition to have uncommon casing size and specification, 16" intermediate semi flush liner connection and 13-3/8" full flush intermediate casing connection to ensure sufficient annular area and less restriction during running to bottom.

The relentless effort to secure one the most critical ERD well construction phase has really paid off by allowing the next phase of operation to be executed as per plan thus assuring the overall well objective is met.
Analysis of South Australian Onshore Oil & Gas Well Decommissioning and Potential Impact on Regulatory Compliance, Environmental and Corporate Risk — Unified Risk Code
Authors: Kokkoni Panayiotis Peter , Salmachi Alizera
Published: October 2021

The Cooper/Eromanga Basin is in central Australia and has been the focal point for oil and gas exploration and development in South Australia since the first commercial hydrocarbon discovery in 1963. In the years and decades following, thousands of subsequent wells have been drilled. The CE Basin spans across four states and territories covering an area ~35,000km2. The concentration of South Australian wells is situated in the Northeast of the state and sparsely concentrated in a 300km × 500km area (Figure 1) with the wells in this area being the focus of this research study.

Well decommissioning commonly referred to as Plug and Abandonment (P&A) aims to restore the natural integrity of geological formations that existed prior to drilling. It is a mandatory requirement for all wells and must account for the effects of any foreseeable chemical and geological processes from an eternal standpoint. The minimum requirement for abandonment of the South Australian wells is governed by Objective 6 Cooper Basin State Environmental Objectives (SEO): Drilling, Completions and Well Operations, November 2015 guidelines, which provides the compliance criteria for appropriate barrier installation and verification.

Well complexity is determined by the difficulty in achieving this minimum compliance requirement based on available data of well conditions, simplified in the form of a risk code.