bluuebunny/crossref_metadata_2025_split huggingface dataset:
Application of Collision-Tolerant Rock Bit with Special Heel Technology for Crowded Offshore Platform Drilling Environment - First Implementation in Asia Pacific
Authors: Grimes Robert E. , Drew Jake , Feizal Aulia Hamdani , Riambomo Eka Pambudi , Durachman Ridwan 
Published: October 2021

Abstract
Santan is a mature gas field in East Kalimantan, Indonesia, where infill wells are being drilled to increase production rates. A crowded offshore platform in the Santan Field increases well trajectory complexity and presents a heightened risk of wellbore collision issues. The high number of wells on this directional pad in the shallow water drilling environment results in densely populated existing conductor pipe. Thorough drilling assessments and anti-collision directional drilling mitigation practices are key to successfully executing safe and reliable drilling operations.
To further mitigate the likelihood of a well control situation resulting from a collision with a neighboring conductor or casing, a 17.5 in. IADC Classification 115 Steel Tooth (ST) rolling cone bit with special heel technology was utilized in the Santan field. This is the first time this technology has been applied in Asia Pacific. The ST bit employs continuous disk shaped heel rows on all three cones rather than conventional ST chisel shaped heel row teeth which have multiple sharp cutting edges. The special disk heel rows are designed to deflect off casing in the event of a collision in order to minimize damage to conductor or casing.
The use of the special disk heel technology bit has yielded positive results to date. The bits have successfully and safely drilled in a critical zone where the center-to-center distance between slots was as low as 1m. The drilling performance and well trajectory targets were achieved. Reduced drilling parameters were used as per anti-collision and lost circulation practices, however, the overall rate of penetration (ROP) and directional behavior with the special disk heel bit was similar to conventional ST bits used in offset wells without collision risks. Turn and build rates of up to 4.8°/100 ft were achieved on a bent motor bottomhole assembly, while the average distance to the plan at the end of the section was only 10.59 ft. A series of laboratory casing collision tests was conducted during the development of the special disk heel bit which demonstrated a 75-80% reduction in casing collision damage as compared to a conventional IADC 115 ST bit. Overall, this technology minimizes the detrimental effects should a collision occur, without sacrificing ROP or steerability performance.
The special disk heel ST bit has proven to cause significantly less damage to casing from a collision event than any other bit type – ST, tungsten carbide insert (TCI), or PDC bits, while still providing excellent ROP and steerability in soft formation, shallow water applications. This technology allows operators to more confidently place additional wellbores in crowded offshore template environments for greater field development from a single platform.
An Innovative Solution for Production Enhancement Using Expandable Casing Patch Technology
Authors: Sharma Hemant K. , Al-Mulhim Abdulrahman. K. , Ahmed Danish , Gaby Mohamed 
Published: October 2021

Abstract
E&P operators are looking at innovative solutions to control water production in horizontal oil well producers, to maximize their assets’ value. The operators are putting greater emphasis on maximizing oil production from the existing assets instead of performing sidetrack or drilling new wells. Completing wells with equalizer completions; inflow control device (ICD) separated by openhole packers is one such solution.
Two kinds of equalizers are used for entry of wellbore fluids; Active ICDs and Passive ICDs. For wells completed with Active ICDs, a shifting tool can be used to close the water producing ICDs. However, for wells completed with passive ICDs, plugs with cement can be used, which will isolate the section below, leaving much of the oil behind. For wells in which the heel or the middle section starts to produce water, there was no solution, but to live with it or re-sidetrack the well.
Recently, a new technology of expandable steel technology has been selected, and specifically customized for ICDs isolation purposes. The patch is corrosion resistant alloy (CRA) material, which was selected to cope with the harsh corrosive environment. Pipe geometry had to be adjusted to enable "Patch thru Patch" capacity. Despite the tight restrictions of the well, the use of this technology allowed to keep enough clearance after installation to pass another Patch thru later on, if required.
Prior to performing the isolation of the ICD, production logs of the horizontal section were carried out to analyze the production and locate precisely the high-water producing zones. Three (3) Patches were successfully deployed rigless using smart coiled tubing. The real time monitoring enabled accurate positioning and smooth down hole pressure control.
Post patch installation, wellbore path remained clear, enabling production from the bottom zone. The well performance improved with substantial reduction in water production and consequent incremental increase in the oil production. Isolating the dominating water contributing ICDs, contributed to increase the oil contribution from the other ICDs. This was confirmed by another production log performed post patch installation. This was the first installation of Xpandable Steel Patch across ICD's worldwide.
This paper will highlight the technology and its application, solution selection process and the operational deployment of the Xpandable Steel Patch including real-time monitoring capabilities of instrumented Coil tubing (CT) which can be leveraged to accurately install the patches.
Designing a Robust Surfactant Based SP Formulation in High Clay Containing Low Permeability Indonesian Field
Authors: Bachtiar Andi , Octaviani Octaviani , Fauzi Iqbal , Roy Sayak , Company Roberto , Brunet-Errard Lena , Mascle Matthieu 
Published: October 2021

Abstract
Indonesian oil and gas reserves have been depleting since 2000 with no major addition of new oil reserves. Therefore, it is imperative to increase national oil production by optimizing the mature fields through the implementation of successful EOR technology. Out of this approach, a comprehensive study has been carried out on the targeted field by exploring the potential of surfactant-polymer (SP) flooding. This article describes the formulation design, optimization, and lessons learned leading up to a successful and robust chemical EOR formulation designing for a low permeability and high clay (&gt;20% clay) containing Indonesian oil field.
The detailed workflow consists of analysis of fluid and rock characterization, tailor-made SP formulation designing, optimization and coreflood validation as presented in previous papers (Bazin, 2010). A series of surfactant formulation were designed and screened synthetically through a validated High Throughput Screening (HTS) methodology using a robotic platform combined with microfluidic tools for ultra-low interfacial tension (IFT), solubility, compatibility with brine and polymer. Rock mineralogy has played an important role due to heterogeneity and very high (&gt;20%) clay content. Surfactants retention through adsorption on reservoir rocks was the main constraint to achieve high performance and economical chemical EOR for the targeted field. Specific strategies by optimizing the surfactant formulation and by injecting adsorption inhibitor thus needed to be deployed to mitigate high surfactant retention.
The detailed laboratory screening experiments conclude that the designed robust SP formulation is able to induce ultra-low IFT, excellent solubility and compatibility at the injection water salinity. The dynamic coreflood experiment using reservoir rock shows high incremental oil recovery (&gt;60% ROIP) in short SP slug injection.
As expected from the nature of rock, adsorption was the main challenge encountered during the course of this study, which resulted in a very promising oil recovery in economically realistic conditions.
First Successful Channel Fracturing Job, in the Middle East, Across Darcy-Permeability Sandstone Formation in Challenging Preperforated Liner Disposal Well Proves to be the Optimum Solution for Enhancing Injectivity
Authors: Fawwaz Abdullah A. , Al-Obaid Rashid H. , Kurniadi Stevanus Dwi , Khan Abdul Muqtadir , Al Jalal Ziad , Zaouali Zouhir 
Published: October 2021

Abstract
Produced water is a byproduct of the production cycle that often creates problems for handling and disposal. In Khafji Joint Operation (KJO), thousands of BWPD were being produced every day and disposed of by pumping the water back into the A formation. This formation is sandstone and has a permeability range over one Darcy. To improve the economics of this project, KJO set an injection target rate of 30,000 B/D per well at a maximum of 1,500-psi wellhead injection pressure due to surface facility constraints. Several completion and stimulation methods were selected to enhance the injectivity rate of these disposal wells.
A pilot project was conducted to understand the best methods for injector well development. The well was drilled slanted across the reservoir to increase the reservoir contact area. Openhole and preperforated liners with different upper completion tubing sizes (i.e., 5-in. and 7-in. tubing) were compared to set the baseline of injectivity. Coiled tubing matrix acidizing and hydraulic fracturing were performed in this pilot well to enhance the injectivity. In each different methodology, a series of injection and surveillance tools was deployed to quantify the results.
Upon completion with the 5-in. tubing, the pilot well could not achieve the target injectivity rate without well stimulation. An improvement after acid stimulation via coiled tubing was observed, although it was not able to achieve the injectivity target. Completing the well with 7-in tubing improved the injectivity rate slightly, but the injection pressure was still relatively high. Finally, and despite the combination of all challenges in this well, the first channel fracturing in a preperforated injector well in the Middle East was successfully performed. The post-fracturing evaluation shows that channel fracturing is the optimal stimulation method, increasing the injectivity index in this well ninefold compared to matrix acidizing. These results suggest that the implementation of effective fracturing design and operations improves the economics of the project. The results also demonstrate the importance of surveillance activities and their analysis to guide the technical decision and technology deployment.
To overcome the challenges, a clear and robust workflow and solution execution and surveillance methods were developed. The pilot project illustrates the importance of having the right data to guide decisions and a rigorous QA/QC approach before, during, and after fracturing to achieve successful delivery.
Vaca Muerta: An Emerging Shale Petroleum Reservoir
Authors: Abd Karim Rahimah Binti , Aguilera Roberto 
Published: October 2021

Abstract
Argentina is ranked second globally in terms of technically recoverable shale gas, and fourth in shale oil (EIA 2015). The most prolific shale is the Vaca Muerta formation. The objective of this paper is to present geological and reservoir characterization, drilling and production strategies, as well as historical performance and economics of Vaca Muerta. The word petroleum as used in this paper includes oil, natural gas, and natural gas liquids.
This paper describes natural fractures and their impact on hydrocarbon productivity. The successful commercial production from this unconventional resource has been driven by many factors, including regional geology, availability of advanced technology such as horizontal drilling and multi-stage hydraulic fracturing, as well as domestic and regional hydrocarbon demand (Sierra 2016). Vaca Muerta itself is very unique with multiple hydrocarbon windows from east to west, ranging from dry gas to wet gas, to light oil and black oil.
The productivity of Vaca Muerta is benchmarked to some of the best US shale plays such as the Eagle Ford and the Marcellus. Vaca Muerta contains 1202 Tcf of risked gas in-place and 270 billion barrels of risked oil in-place. It is estimated that 308 Tcf and 16 billion barrels of these resources are technically recoverable (EIA 2015). To date, the total number of horizontal wells exceeds 600, mostly drilled in the black oil window (Secretaria de Energia de Argentina 2020; Wood Mackenzie 2020b). Dubbed the ‘golden goose’ of Argentina, the last decade has seen rapid exploration and development activities. The Argentina state oil company (YPF) leads the development in this region together with its partners. In 2019, production from Vaca Muerta reached 90,000 bbl/d of oil and 1180 MMcf/d of gas, contributing 21% of Argentina's total production (Secretaria de Energia de Argentina 2020; Wood Mackenzie 2020b). YPF predicted these rates would increase by 150% in 2022 (Rassenfoss 2018). Part of this increase will be contributed by La Amarga Chica block, where YPF and its partner, PETRONAS approved their 30-year master development plan in late 2018 to deliver 54,000 boe/d by 2022 (Zborowski 2019). This production increase has obviously been delayed due to the COVID-19 pandemic.
The novelty of this paper is integration of geological and reservoir characterization, drilling and production strategies, as well as historical performance and economics of Vaca Muerta. It is concluded that oil and gas potential in the Vaca Muerta shale is significant and rivals the potential of some of the shales widely developed in the Unites States and Canada.
Pilot Application of a Novel Nano-Clay Relative Permeability Modifier in a Mature Malaysian Offshore Oilfield
Authors: Mohd Shafian Siti Rohaida , Nourreddine Benayad , Zakaria Nur Atiqah , Nik Norizam Nik Nor Azrizam , Borhan Noorazlenawati , M Nawi M Shakir , M Zaki M Haziq Farhan , Khairudin Azri , Abdullah Sofian , Ahmed Abdelazim Abbas , M Saaid Ismail 
Published: October 2021

Abstract
Excessive water production associated with a decrease in hydrocarbon production is becoming a big challenge in matured offshore fields. Producing a barrel of water requires more energy that creates major economic impact on the profitability of an oil-field project. This paper presents a case study for water shut off treatment with a novel relative permeability modifier (RPM) (nano-clay). The nano-clay demonstrated high resistance to water flow (RRFw &gt;10) and less effect to oil flow (RRFo &lt;5) and capable to change the rock surface's wettability to more water wet. The main pilot objective was to assess the chemicals performance as part of production enhancement effort to reduce the water production from 90% to 50% water cut and to accelerate the oil production. We discussed the overall workflow, pilot execution, challenges and best practices including the laboratory results with the reference during research and development stage. The well treatment consists of bull-heading a pill of pre-flush of treated sea water for injectivity test, followed by nano-clay injection, post-flush with treated sea water, soaking for 48 hours and flow back the well. Pilot execution was completed successfully and safely within the target execution plan and are currently in monitoring stage. The post-treatment results and the overall economic success will then decide the future replication plan of this new water shut off technology.
Extreme Well Electrical Submersible Pump: Altering Perception in Artificial Lift Selection
Authors: Alfajri Reza , Sipahutar Herbert , Irianto Heru , Kananta Harry , Balya Catur Sunawan , Ghiffari Muhammed , Maltsev Alexander , Lobanov Andrei 
Published: October 2021

Abstract
Electrical Submersible Pump (ESP) is an artificial lift that often associated with big production rate, which is at least 300 bbls/day. ESP also has limitation in handling unconsolidated sand reservoir, high GOR wells, and minimum casing ID. As technology flourished, these handicaps for an ESP well are no longer valid. A breakthrough was established for ESP utilization. However people's perception of ESP persists. Extreme well ESP is changing that perception.
There are three types of extreme well ESP: high solid content, high GOR, and slim-line ESP. High solid content ESP has open impellers. This type of impeller creates no space between impeller and diffuser, hence no solids accumulation. Multiphase pump (MPP) is used to handle high GOR problem. MPP stage design has axial screw type impeller and gas handling diffuser. Gas from reservoir fluid will be compressed and broken into smaller bubbles resulting in homogenous gas-liquid mixture, hence no gas lock during production. For well with small casing ID e.g., 4-1/2" casing, slim-line ESP with 3.19" outside diameter is utilized.
These three types of extreme well ESP were all utilized in Central Sumatera Asset of Pertamina EP. High solid content ESPs were installed in five wells (MJ-134, MJ-132, MJ-128, STT-25, and KTT-23) in four different structures with production range of 30 to 1200 bbls/day. Basic Sediment (BS) number in this asset varies from 0.1% up to 40%, which results in suspending wells and repeating well services. In wells MJ-134, high solid content ESP was able to produce up to 50% BS number at the beginning of production. It showed excellent lifting capability in severe sand problem condition. While in wells STT-25 and KTT-23, utilizing high solid content ESP increases well's lifetime and generates gain in production. High GOR ESPs were installed in wells PPS-01 and SGC-15. Both wells has around 2000 scf/stb GOR. Conventional ESP would have a hard time producing these gassy wells. By using MPP, well PPS-01 produced smoothly and even later optimized to have bigger production. Producing well SGC-15 faced another handicap in form of scale deposition. Scale preventer was also installed for this well. Slim-line ESP was installed in well BJG-01 that has 4-1/2" casing. Grossing up the wells with slim-line ESP contributes production gain.
Since October 2019 this project has produced cumulative production of 56,199 bbls oil and counting, and been considered successful in solving extreme well problems. Being proven able to handle high BS number, high GOR, and produce well with small casing size, extreme well ESP is altering old mindset in ESP utilization. All of handicaps mentioned above were redeemed obsolete. This breakthrough starts the dawn of new perception in artificial lift selection.
The Research and Application of Cementing Isolation Technology in High Porosity and Permeability of Developed Clastic Rock Reservoir in Tarim Basin
Authors: Liu Hongtao , Ai Zhengqing , Zhang Jingcheng , Yuan Zhongtao , Zeng Jianguo , Xu Liqun , Tang Bin 
Published: October 2021

Abstract
The average porosity and permeability in the developed clastic rock reservoir in Tarim oilfield in China is 22.16% and 689.85×10-3 μm2. The isolation layer thickness between water layer and oil layer is less than 2 meters. The pressure of oil layer is 0.99 g/cm3, and the pressure of bottom water layer is 1.22 g/cm3, the pressure difference between them is as bigger as 12 to 23 MPa. It is difficult to achieve the layer isolation between the water layer and oil layer.
To solve the zonal isolation difficulty and reduce permeable loss risk in clastic reservoir with high porosity and permeability, matrix anti-invasion additive, self-innovate plugging ability material of slurry, self-healing slurry, open-hole packer outside the casing, design and control technology of cement slurry performance, optimizing casing centralizer location technology and displacement with high pump rate has been developed and successfully applied.
The results show that: First, the additive with physical and chemical crosslinking structure matrix anti-invasion is developed. The additive has the characteristics of anti-dilution, low thixotropy, low water loss and short transition, and can seal the water layer quickly. Second, the plugging material in the slurry has a better plugging performance and could reduce the permeability of artificial core by 70-80% in the testing evaluation. Third, the self-healing cement slurry system can quickly seal the fracture and prevent the fluid from flowing, and can ensuring the long-term effective sealing of the reservoir. Fourth, By strict control of the thickening time (operation time) and consistency (20-25 Bc), the cement slurry can realize zonal isolation quickly, which has achieved the purpose of quickly sealing off the water layer and reduced the risk of permeable loss. And the casing centralizers are used to ensure that the standoff ratio of oil and water layer is above 67%. The displacement with high pump rate (2 m3/min, to ensure the annular return velocity more than 1.2 m/s) can efficiently clean the wellbore by diluting the drilling fluid and washing the mud cake, and can improve the displacement efficiency.
The cementing technology has been successfully applied in 100 wells in Tarim Oilfield. The qualification rate and high quality rate is 87.9% and 69% in 2019, and achieve zone isolation. No water has been produced after the oil testing and the water content has decreased to 7% after production. With the cementing technology, we have improved zonal isolation, increased the crude oil production and increased the benefit of oil.
Wellbore Strengthening Design Criteria and Enhanced Fracture Gradient for Widening Stable Mud Weight Window and Enabling Safe and Efficient Drilling in Depleted Reservoirs
Authors: Tan Chee Phuat , Wan Mohd Zainudin Wan Nur Safawati , Razak M Solehuddin , Zakaria Siti Shahara , Nesan Thanavathy Patma , Seyyedi Mojtaba , Wu Bailin , Firns Stephen 
Published: October 2021

Abstract
Drilling in permeable formations, especially depleted reservoirs, can particularly benefit from simultaneous wellbore shielding and strengthening functionalities of drilling mud compounds. The ability to generate simultaneous wellbore shielding and strengthening in reservoirs has potential to widen stable mud weight windows to drill such reservoirs without the need to switch from wellbore strengthening compound to wellbore shielding compound, and vice-versa. Wellbore shielding and strengthening experiments were conducted on three outcrop sandstones with three mud compounds. The wellbore shielding stage was conducted by increasing the confining and borehole pressures in 4-5 steps until both reached target pressures. CT scan images demonstrate consistency of the filtration rates with observed CT scanned mud cakes which are dependent on the sandstone pore size and mud compound particle size distributions. In wellbore strengthening stage, the borehole pressure was increased until fracture was initiated, which was detected via borehole pressure trend and CT scan imaging. The fractures generated were observed to be plugged by mud filter solids which are visible in the CT scan images. The extent of observed fracture solid plugging varies with rock elastic properties, fracture width and mud compound particle size distribution. Based on the laboratory test data, fracture gradient enhancement concept was developed for the mud compounds. In addition, the data obtained and observations from the tests were used to develop optimal empirical design criteria and guidelines to achieve dual wellbore strengthening and shielding performance of the mud compounds. The design criteria were validated on a well which was treated with one of the mud compounds based on its mud loss events during drilling and running casing.