bluuebunny/crossref_metadata_2025 huggingface dataset:
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

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 >10) and less effect to oil flow (RRFo <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

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 As technology flourished, these handicaps for an ESP well are no longer valid.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

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

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.
Application of Heat Treatment to Prevent Fracturing Fluid-Induced Formation Damage and Enhance Matrix Permeability in Shale Gas Reservoirs
Authors: Chen Mingjun , Li Peisong , Kang Yili , Gao Xinping , Yang Dongsheng , Yan Maoling
Published: October 2021

The low flowback efficiency of fracturing fluid would severely increase water saturation in a near-fracture formation and limit gas transport capacity in the matrix of a shale gas reservoir. Formation heat treatment (FHT) is a state-of-the-art technology to prevent water blocking induced by fracturing fluid retention and accelerate gas desorption and diffusion in the matrix. A comprehensive understanding of its formation damage removal mechanisms and determination of production improvement is conducive to enhancing shale gas recovery. In this research, the FHT simulation experiment was launched to investigate the effect of FHT on gas transport capacity, the multi-field coupling model was established to determine the effective depth of FHT, and the numerical simulation model of the shale reservoir was established to analyze the feasibility of FHT. Experimental results show that the shale permeability and porosity were rising overall during the FHT, the L-1 permeability increased by 30- 40 times, the L-2 permeability increased by more than 100 times. The Langmuir pressure increased by 1.68 times and the Langmuir volume decreased by 26%, which means the methane desorption efficiency increased. Results of the simulation demonstrate that the FHT process can practically improve the effect of hydraulic fracturing and significantly increase the well production capacity. The stimulation mechanisms of the FHT include thermal stress cracking, organic matter structure changing, and aqueous phase removal. Furthermore, the special characteristics of the supercritical water such as the strong oxidation, can not be ignored, due to the FHT can assist the retained hydraulic fracturing fluid to reach the critical temperature and pressure of water and transform to the supercritical state. The FHT can not only alleviate the formation damage induced by the fracturing fluid, but also make good use of the retained fracturing fluid to enhance the permeability of a shale gas reservoir, which is an innovative method to dramatically enhance gas transport capacity in shale matrix.
Field Optimization Via Data Approach: A Case Study of Data Mining for Tight Gas Flowback Evaluations
Authors: Liu Yuan , Li Bin , Zhang Hongjie , Yang Fan , Wang Guan , Wang Weikan , Zhao Jinyu
Published: October 2021

The economics of tight gas fields highly depend on the consistency between expected production and the actual well performance. A mismatch between the reservoir quality and the well production often leads to a review of the individual well. However, such mismatch may vary from case to case, and it is hard to perform a field-level analysis based on individual well reviews. We introduce a new method based on data mining to assist the field-level diagnosis.

LX gas field is located the in eastern Ordos basin. Compared to the main gas field in the center of the basin, LX field is less predictable in well performance. This predictability issue hinders field development in LX field because the field economics are substantially jeopardized by the inconsistency between the reservoir quality and the production performance.

The traditional workflow to understand this issue at the field level is to review the details of a large number of individual wells in the area. This is typically an intense task, and too much detail from multiple disciplines may hide the true pattern of the field behavior. To resolve this issue, we applied data mining in our field development diagnosis workflow.

Our new workflow in LX area started with the existing field datasheet, including logging summaries, completion treatment reports, and flowback testing datasheets. With the data extracted from these different sources, we visualized the consolidated information in various plots and graphs based on regression analysis, which revealed the relation between flowback ratio and the production, the flowback rate consistency from the different service suppliers, and the impact of water productions.

The data mining approach helped to generate new understandings in LX gas field. With the in-depth analysis of the flowback data together with reservoir properties and operation parameters, the key problems in the field were identified for further development optimization, and the field economics can be significantly improved. The diagnosis method can be easily adapted and applied to any field with similar problems, and data mining can be useful for almost all large-scale field development optimizations.
Reserves and Resources Management: A Continuous Improvement of the Business Processes
Authors: Hadi Aen Nuril , Leonardo Stephen , Anwar Khairul , Aritonang Tuan Manotar , Dewi Devialina Puspita , Fatimurakhman Fery , Hamza Bayu , Adma Alfariko
Published: October 2021

Managing oil and gas reserves and resources of Pertamina, an Indonesia state owned energy company, has always been challenging processes as the company's portfolio is sparsely located throughout Indonesia. Moreover, since November 2013 the company has also managed its international assets spread across three regions, namely Africa, Asia, and Middle East. In total, there are ~480 fields and ~870 geological structures with different degree of geological background, environment, uncertainty, and maturity of the fields/projects. Obviously, to cope with all those complexities, Reserves Management Department need to figure out its way to properly manage reserves and resources of the company.

Reserves and resources of oil and gas is a key strategic priority of the company. It is aligned with both portfolio management and development and production of the assets. Company decision in terms of work program and budget is also mainly derived from reserves and resources potential of the projects. Therefore, to obtain a standardized reserves and resources management, the company has launched company guideline which is mainly influenced by SPE Petroleum Resources Management System (SPE-PRMS, 2007). SPE-PRMS is a project-based system, where reserves and resources estimation, categorization, and classification are on project basis. To properly manage all the projects, since 2019, Reserves Management Department introduced a tool named Project Box which enable reserves analyst to properly map all the projects, evaluate the portfolio, and monitor the progress of the project both in development and exploration phase. Furthermore, to be aligned with company's digitalization campaign, all the reserves and resources data, Project Box, and many other strategic information are stored and maintained in an in-house software named Promyst which will be launched in early 2021. This tool will enhance data accessibility for both management and analyst, increase data integrity and security, provide data analysis platform, moreover this software could also generate cost efficiency for the company.

In 2017, along with the final version of the company guideline, the company has fully adapted PRMS. This paper will explain how the company adapt PRMS to its company guideline in which some necessary adjustments took place with respect to company's business processes, the application of Project Box throughout all company's subsidiaries, and implementation of Promyst along with its features and future projection of the software. The result and benefit of implementing those items will be explained in this paper. These extensive works performed by the Reserves Management Department contribute significantly to the company not only for technical but also for commercial aspects therefore promoting a good corporate strategic planning and decision making.
Success Deployment and Operation of Downhole Casing Valve Improves Tripping and MPD Operation While Saving 5 Drilling Days Through Total Loss Circulation in Basement
Authors: Joydi Zein Mirza , Fikri Irawan , Sekar Dewayani Wuri , Andry Prasthio
Published: October 2021

Southern part of Sumatra is known for its high deliverability hydrocarbon gas formation with flow rate up to 200 MMSCFD produced from a single well. The fractured network present mainly in its granite basement formation posed as the primary hydrocarbon contributor aside to the carbonate zone. High formation pressure with massive gas reservoir as its driving mechanism combined with total loss circulation due to geological fault in the same section, lead to operation with various hazard combined which demands potent solution. Advanced technologies required to execute the operation in safest and efficient manner.

Downhole Casing Valve (DCV) is one of Managed Pressure Drilling (MPD) equipment used to support operation with deep and high-pressure formation, installed alongside with casing to provide sealing of the well at depth. Equipped with flapper type valve and full borehole size, DCV which is surface controlled, enables operator to seal the well in the absence of any string. The seal created by DCV allows the string to be pulled out preventing to kill a live well.

The South Sumatra blocks depicts enormous potential gas reservoir. Located in the fault of basement where total loss circulation will occur in highest probable manner. Utilization of chemical mixed mud was impractical considering the total loss circulation. Thus, pressure exerted from fluid column and pumping flow rate from string needs to be compensated by surface backpressure. In addition, to accommodate deep footage penetration of the section, hard basement formation, complex completion running sequence, and multiple tripping for BHA changes, requirement of DCV shifted from nice-to-have into a must-have segment. Without the need of killing the well nor changing the mud system, DCV allows tripping operation to be completed safely and efficiently by sealing the well with its flapper, saving costs and time on each tripping operation. DCV utilization successfully supports drilling high-pressure gas reservoir through basement fault until target depth reached safely and efficiently.
Troubleshooting Cable Deployed Thru Tubing Electrical Submersible Pumps: A Case Study from South East Asia
Authors: Anand Saurabh , Rosland Eadie Azahar B , Ghonim Elsayed Ouda , Riyanto Latief , Abu Bakar Khairul Azhar B , Mohd Radzuan Nurul Asyikin Bt , Mat Khair Nusheena Bt , Zaki Shazana M
Published: October 2021

PETRONAS had embarked on an ambitious thru tubing ESP journey in 2016 and had installed global first truly rig less offshore Thru Tubing ESP (TTESP) in 2017. To replicate the success of the first installation, TTESP's were installed in Field – T. However, all these three TTESP's failed to produce fluids to surface. This paper provides the complete details of the troubleshooting exercise that was done to find the cause of failure in these wells.

The 3 TTESP's in Field – T were installed as per procedure and was ready to be commissioned. However, during the commissioning, it was noticed that the discharge pressure of the ESP did not build-up and the TTESP's tripped due to high temperature after 15 – 30 mins of operation. Hence none of the 3 TTESP's could be successfully commissioned. Considering the strategic importance of TTESP's in PETRONAS's artificial lift plans, detailed troubleshooting exercise was done to find the root cause of failure to produce in these three wells. This troubleshooting exercise included diesel bull heading which gave some key pump performance related data.

The three TTESP's installed in Field – T were of size 2.72" and had the potential to produce an average 1500 BLPD at 80% water cut. The TTESP deployment was fully rigless and was installed using 0.8" ESP power cable. The ESP and the cable was hung-off from the surface using a hanger – spool system. The entire system is complex, and the installation procedure needs to be proper to ensure a successful installation. The vast amount of data gathered during the commissioning and troubleshooting exercise was used for determining the failure reason and included preparation of static and dynamic well ESP model. After detailed technical investigative work, the team believes to have found the root cause of the issue which explains the data obtained during commission and troubleshooting phase. The detailed troubleshooting workflow and actual data obtained will be presented in this paper. A comprehensive list of lessons learnt will also be presented which includes very important aspects that needs to be considered during the design and installation of TTESP. The remedial plan is finalized and will be executed during next available weather window.

The key benefit of a TTESP installation is its low cost which is 20% – 30% of a rig-based ESP workover in offshore. Hence it is expected that TTESP installations will pick-up globally and it's important for any operator to fully understand the TTESP systems and the potential pain points. PETRONAS has been a pioneer in TTESP field, and this paper will provide details on the learning curve during the TTESP journey.
Proven Technologies and Solutions for Successful Production Enhancement in Malaysia with Array Production Logging
Authors: Vevakanandan Valsan , Ting Angelina Jia Hui , Kho Sze Fong , Ho Chen Nyap , Tan Aaron Qun Jie , Manzar Muhammad Abrar , Lim Eng Chuan
Published: October 2021

M field is a faulted anticline structure that lies in a deepwater turbidite environment. Field Development started in late 2016, with 10 oil producers and 2 water injectors. Within 2 years of production, significant GOR increase in some of the wells led to production curtailment, which has impacted the field production promise. Poor injectivity seen in one of the water injectors also led to an assumption of compartmentalization or sandface plugging/damage that required investigation. In order to evaluate intervention opportunities to mitigate against the high GORs and to determine the cause of the poor injectivity, production logging tools were proposed in four candidate wells.

The objectives of the logging campaign were:

To understand the gas influx profile into the well and how different compartments are contributing to the GOR Assess behaviour of G/O, O/O, O/W crossflows and their impact on reservoir depletion profile Aid decisions in requirements for downhole controls (i.e. AICD placement) vs surface controls Provide opportunity to couple PL logs with PNC logs to identify potential GOCs, estimate gas/water saturations and determine if there are any bypassed oils

Based on the candidate wells, the following challenges were present:

Highly-deviated/horizontal wells requiring complex conveyance solutions Multiphase flows (gas, oil and potentially water) in highly deviated conditions which further complicates fluid phase contribution calculations and velocity modeling Rig up height limitations on the platform which requires shorter logging tool strings High flowrates with tool lift limits requiring careful modelling work to ensure risks are understood and minimized

In view of these challenges, a new Array Production Logging Tool (henceforth called New-APLT) was proposed as an alternative to the previous generation APLT. It has a more robust design with co-located sensors in a single module with additional optical sensors that improves flow measurement and gas detection.

Additionally, screen tracers sampling was proposed in one well, which would help calibrate the tracer interpretations against actual fluid rates. The novel approach and synergistic efforts amongst many disciplines led to a successful execution of the logging campaign, and the first ever deployment of the New-APLT tool on e-line tractor. The timely results from the campaign which coincided with a 4D seismic acquisition has helped to justify downhole control options for some of the wells, and potentially helped to avoid costly remedial work on the water injector. The valuable dataset will also influence the infill development well campaign location, design and well count.
Drilling and Completion Waste Reutilization and Zero Discharge Technology Used in China Bohai Bay
Authors: Wang Kunjian , Liu Pengfei , Hou Xinxin , Wang Pan , Zhu Pei , Hao Mingxuan , Li Dejiang , Tang Qisheng , Wang Qing , Ge Wenchen , Zeng Xu , Zhang Hao , Zhang Shihao , Chen Kejin
Published: October 2021

With the increasingly stringent national environmental rules, waste produced in drilling and completion process is forbidden to be discharged into the Bohai Bay or reinjected into the formation. The current disposal method of drilling and completion waste in Bohai Oil field has some problems such as high cost, low efficiency and high HSE management and control risk. Faced with these problems, drilling and completion waste reutilization and zero discharge technology has been developed and applied in this region.

In order to reutilize drilling and completion waste which include cuttings circulated from formation, wasted drilling and completion fluids, the following aspects are carried out: Firstly, drilling platform is upgraded to meet the zero discharge requirement: solid control system is modified, cuttings closed transfer system and cuttings treatment system are equipped on the platform to collect and dispose the waste. Meanwhile, recovery and disposal capacity to support different spud drilling are assessed: cuttings transport capacity is up to 15m3/h, which can meet the highest requirements of 12-1/4″ hole drilling when ROP is up to180m/h. Secondly, the well profile is downsized to reduce the production of cuttings, mud and other wastes from the root, which can also improve efficiency and yield cost.

The field application shows that the amount of the waste has been reduced by 41.39%, 39.86% and 41.52% in first, second and third spud drilling, and average ROP is 35%, 28%, 42% higher than similar wells drilled before. Lastly, in drilling and completion fluids system optimization and reutilization aspects, environmentally friendly drilling and completion fluids with low solid content are developed. The experiment shows that the properties of the liquid phase after solid-liquid separation can be reused, and the solid phase with low water content is easy to pack and transport back to land.

Drilling and completion waste reutilization and zero discharge technology introduced in this paper has been successfully applied in more than 40 wells, and the volume of waste drilling fluid is reduced by 80%, which is a trade-off between zero discharge and well construction cost. This technology can also be applied in other offshore oilfield which is inevitable as the environmental rules become more and more strict.
Novel Approach for Selecting Well Candidates and Appropriate Design of Hydraulic Fracturing in Challenging Reservoirs
Authors: Mirza Muhammad , Saadi Hassan Al , Trejo Ricardo Sebastian , Kayumov Rifat , Hilal Ahmed
Published: October 2021

Karim and Haradh reservoirs within the Karim Small Fields (KSF) cluster in the South of the Sultanate of Oman are characterized by low to medium permeability and significant heterogeneity and contain medium to heavy crude oil. Reservoir depths are in the range of 1500 to 2000 m and productive areas are relatively small (around 2 km2 per field).

Over the past 10 years, fields development did not result in sustained oil production despite the close well spacing. Geological and reservoir studies indicated that this is mainly due to the heterogeneity, lack of reservoir continuity and presence of significant wellbore damage in most wells. Accordingly, the KSF operator initiated an appraisal campaign focusing on hydraulic fracturing to stimulate the producing wells and improve the extension of their drainage areas. This campaign resulted in significant improvement in well productivity and the analysis of results indicates good potential for improving the ultimate oil recovery from these reservoirs.

Although the results from hydraulic fracturing campaign are encouraging, they also indicate that appropriate selection of well candidates, key parameters in the fracturing procedure, effects of well completion and impact of well age are very important for successful oil gain. As a result, a comprehensive procedure for selecting and ranking candidate wells for hydraulic fracturing in Karim and Haradh formations has been developed. The procedure includes assessing the impacts of key properties such as fracture height, depth of oil-water contact, thickness of oil column, and distance to faults. In addition, the lessons learned from the previous appraisal campaign will contribute to achieving optimum fracture geometry in future campaigns.

The candidate selection workflow involves understanding the geology, geomechanics, and petrophysics of the wells in which a fracturing operation was performed previously in different formations in KSF. More than 20 existing wells were screened through the candidate selection process using a clear workflow to incorporate all the relevant aspects of the selection criteria. The outcome of the candidate selection phase led to selection of the best wells for fracturing operations in the Karim and Haradh formations. The improvements on the fracturing design have been followed to obtain the optimum fracturing design for the selected wells.
Practical Considerations when Using Capacitance Resistance Modelling CRM for Waterflood Optimization
Authors: Simha Srungeer , Ujjwal Manu , Modi Gaurav
Published: October 2021

Capacitance resistance modeling (CRM) is a data-driven analytical technique for waterflood optimization developed in the early 2000s. The popular implementation uses only production/injection data as input and makes simplifying assumptions of pressure maintenance and injection being the primary driver of production. While these assumptions make CRM a quick plug & play type of technique that can easily be replicated between assets they also lead to major pitfalls, as these assumptions are often invalid. This study explores these pitfalls and discusses workarounds and mitigations to improve the reliability of CRM.

CRM was used as a waterflood optimization technique for 3 onshore oil fields, each having 100s of active wells, multiple stacked reservoirs, and over 15 years of pattern waterflood development. The CRM algorithm was implemented in Python and consists of 4 modules: 1) Connectivity solver module – where connectivity between injectors and producers is quantified using a 2 year history match period, 2) Fractional Flow solver module – where oil rates are established as a function of injection rates, 3) Verification module – which is a blind test to assess history match quality, 4) Waterflood optimizer module – which redistributes water between injectors, subject to facility constraints and estimates potential oil gain. Additionally, CRM results were interpreted and validated using an integrated visualization dashboard.

The two main issues encountered while using CRM in this study are 1) poor history match (HM) and 2) very high run time in the order of tens of hours due to the large number of wells. Poor HM was attributed to significant noise in the production data, aquifer support contributing to production, well interventions such as water shut-offs, re-perforation, etc. contributing to oil production. These issues were mitigated, and HM was improved using data cleaning techniques such as smoothening, outlier removal, and the usage of pseudo aquifer injectors for material balance. However, these techniques are not foolproof due to the nature of CRM which relies only on trends between producers and injectors for waterflood optimization. Runtime however was reduced to a couple of hours by breaking up the reservoir into sectors and using parallelization.
Casing While Drilling Level 2 as Mitigation for Shallow Gas and Loss Circulation Hazards in Surface Section
Authors: Wicaksono Nuring Tyas , Falhum Hanafi Muhamad , Subagio Agung , Ritamawan Radianto , Pratomo Andaru Ibnu , Saragih Anggi Muhammad Sabri , Nasution Hendry Akbarputra , Malik Mahamy Abdul , Budiono Kurniadi , Mardiana Ramadhan Yoan , Noviasta Bonar
Published: October 2021

Casing while drilling Level 2 was introduced to mitigate problems in the surface section of Mutiara and Pamaguan Field in East Kalimantan. These two fields have historical shallow gas and loss circulation hazards in surface section. Following a blowout incident in Pamaguan in 2012, new policy was introduced for drilling the surface section in Mutiara and Pamaguan. A pilot hole must be drilled, and additional surface casing shall be set. Although considered safe, longer drilling days and vulnerability to repeated loss circulation made this method inefficient.

A new approach to mitigate the problem was proposed by introducing casing while drilling Level 2 in 2020 drilling campaign. Many papers already discussed about the effectiveness of casing while drilling to mitigate loss circulation. However, a limited number of papers discuss casing while drilling to mitigate shallow gas. Costeno et al, 2012, discussed the use of casing while drilling to mitigate shallow gas. However, the risk of shallow gas was low and there was no shallow gas record during the execution. This paper specifically discusses about utilizing casing while drilling (CWD) technology to mitigate not only loss circulation, but also shallow gas risks during surface hole interval. Both hazards occurred in several wells during job execution and CWD with its plastering effect has managed to drill troublesome surface hole safely, thus making it the better alternative to achieve efficient drilling in comparison with the previously used pilot hole method.
Flawless Cutting of Tubing and Control Lines by Mechanical Pipe Cutter in Challenging Well Condition Provides an Environmental Friendly Alternative: A Case Study from Brunei
Authors: Kadir Nurul Amali , Das Saikat , Khunthongkeaw Jittbodee , Dayem Jamal , Abdul-Hamid Ashraf , Hassan Shaherol , Noridin Nurdiyana
Published: October 2021

The Electro-Mechanical Pipe Cutter (MPC) is a non-ballistic & non-chemical wireline deployed alternative cutter tool for parting downhole tubular in the process of well abandonment, pipe recovery and retrieving of packer elements. This case study showcases its application in two wells with different challenges in cutting 4.5" tubing viz., (i) with multiple control lines to facilitate fishing operations and (ii) under compression in a highly deviated trajectory.

In Well A, Brunei offshore, the position of the tubing and orientation of the control lines were challenging for ballistic option, along with the possibility of scarring the 9-7/8" casing during the cutting operation. Thus, 3-1/8" OD MPC was used for this job to cut near the coupling, ensuring optimum stand off from casing wall aiming to achieve cutting the control lines in tension. Dual cut were designed to allow the room for a safe cut zone. The primary cut was performed near middle of the joint at ∼1985m, with the tubing in tension. The cut was initiated at a very slow feed (0.2 mm/min) and motor rates (4000rpm), which was gradually increased once the cutting was stable. After the accomplishment of the tubing cut, the parameters were again reduced to carefully cutting through control line. The tubing was successfully retrieved with smooth cut without any over pull indicating it to be completely free. The flawless cutting operation was performed in less than one hour with outmost efficiency.

In another highly inclined Well B, Brunei offshore, MPC was chosen over ballistic because it was needed to be conveyed by tractor and ballistic shock has potential to damage it during the operation. Also the advantage of MPC to perform multiple cuts in one run, made it a preferred choice. In this well, multiple cuts were performed to weaken the joint connection of the tubing to allow the rig to pull it free. It was to overcome the adversity posed by high inclination and the pipe under compression. Three cuts were performed at ∼2996 m, each 20 cm apart with an OD of nearly 4.609". After completion of the job, the circulation was performed with surface return, indicating successful execution and the tubing was retrieved on surface showing a clean cut.

This case study shows the appropriate planning and execution of the mechanical pipe cutter can provide an efficient, environment friendly and safe alternative to cut tubing and control line in the challenging condition especially when an explosive and chemical cutter options are not considered suitable.
Thickness Investigation and Prevention Strategy of Hydrate Deposition During Avoidance Typhoon for Deep Water Gas Well
Authors: Tong Shikun , Wang Zhiyuan , Zhang Jianbo , Chen Zhangrui , Li Yingchao , Sun Baojiang
Published: October 2021

The investigation of hydrate deposition is a significant basis for the hydrate prevention strategy during avoidance typhoons for deepwater gas wells. Shut-in operation is a necessary procedure due to avoidance typhoon, the hydrate intrinsic kinetic potential increases the growth rate under shut-in conditions. We establish the model of hydrate thickness investigation and the simulations illustrate that the hydrate thickness layer is relatively minor during avoidance typhoon. Meanwhile, hydrate is aggravated by the environment of low temperature and strong disturbance near the mud line due to production after avoidance typhoon. We discuss the variation of temperature profile and concentration of ethylene glycol during restart operation. The concentration variation of the ethylene glycol on the induced flow show after restart operation that the hydrate inhibitor satisfies the hydrate prevention requirements. This research provides a significant design for the hydrate management program during avoidance typhoon for deepwater gas wells, which is useful to the development of traditional avoidance strategy and decreased the cost of hydrate inhibitors.
Unlocking Marginal Resources through Synergy between Subsurface and Surface Entities
Authors: Atasi Ronald , Prabowo Albertino , Siboro Mitterank
Published: October 2021

Tunu is one of the biggest gas fields in Indonesia with 1400 km2 area in Mahakam Delta, East Kalimantan. This field has been producing since 1990 with cumulative production of more than 9.5 tcf and 190 mbbl condensate by the end of 2020 from over 1000 operating wells. Today, Tunu field contributes for approximately 40% of Mahakam production. After 30 years of production, Tunu production level is currently in declining phase, shown by its yearly production profile which exhibits a declining trend since 2008. Furthermore, Tunu well development project was considered marginally economical due to depleting reserve per well. Thus, an integrated study was conducted in order to reduce surface expenditure cost of Tunu pipeline based on current operating parameters. The study consisted of WHSIP history matching to determine new pipeline design pressure, evaluation of future wells production lifetime, and adjustment of pipeline corrosion allowance based on actual corrosion rate observed in Tunu field. Results show that most of future Tunu wells are predicted to have WHSIP below 200 barg and 1.5 to 3 years’ production lifetime. Corrosion rate in Tunu field as measured using corrosion coupon in piping with corrosion inhibitor injection is found to be less than 1 mm/20 years. Therefore, corrosion allowance for Tunu pipeline is optimized from 5 to 3 mm for 10-years design lifetime. For exceptional circumstances where actual well WHSIP > 200 barg, other method of producing the well will be implemented. Hence, by integrating recent subsurface behavior (WHSIP and well lifetime) with surface understanding (corrosion rate), it was then proposed new pipeline design for Tunu development. This study has generated USD 13 million cost saving for pipeline procurement in 2020. Moreover, implementation of the new pipeline design reduces 40% of pipeline unit cost for future pipeline procurement. This study has become the basis for future well development projects in Tunu field which significantly prolong Mahakam's production sustainability.
The Application of Maine Petrophysical Method; Adding Resources by Explore the Opportunity in Low Resistivity Pay Reservoir
Authors: Reza Mohammad , Arieffiandhany Riezal , Irawan Debby , Shofiyuddin S , Prihanto Darmawan Budi
Published: October 2021

Manifestation of Low Resistivity Pay (LRP) Existences in ONWJ Area because of Fine Grained, Superficial Microporosity, Laminated Shaly Sand and Electronic Conduction. Water saturation petrophysical analysis for LRP Case due to those reason above can be solved by electrical parameter determination with Type Curve. But to overcome the LRP caused by Laminated Shaly Sand, the use of high resolution resistivity logs that are close to the resolution of thin bed reservoir is a must. Alternative solutions, conventional high resolution resistivity logs, namely Micro Spherical Focused Log (MSFL) are used to interpret thin bed reservoirs that have the hydrocarbon potential. This intergrated petrophysical analysis is called MAINE Petrophysical Method

The Petrophysical MAINE method is the development of the TECWAL (Type Curve, Core and Water Analysis) method which leaves question marks on Laminated Shaly Sand Reservoir and the possibility of variations in the Electrical Parameter and Water Saturation Irreducible (SWIRR) dependent on Rocktype. The Basis of the MAINE Method is the Worthington Type Curve with some assumptions such as Each rocktype has a different value of Bulk Volume of Water (BVW) and BVW can be used to determine the SWIRR value of each rocktype and Each rocktype has different electrical parameter m and n. In the process, the use of J-Function and Buckles Plot is applied to help determinet Rocktype and BVW values. The rocktype will be the media in distributing the value of Electrical Parameter generated by the Type Curve and the value will be used in water saturation calculation. In Laminated Shaly Sand Reservoir, Rocktyping will be analyzed more detail using the High Resolution Conventional Log, Micro Spherical Focused Log (MSFL). The expected final result of this analysis is the more reliable Water Saturation (SW) and the integration of water saturation values in the Buckles Plot which can help in determining the transition zone in order to avoid mistakes in determining the perforation zone.

Through the MAINE Petrophysical Method, there is a decrease in water saturation from an average value 86% to 66% or a decrease 23%. This result is quite significant for the calculation of reserves in the LRP zone. By integrating this method with the Buckles Plot, it can help the interpreter to determine the perforation interval in order to avoid water contact or the transition zone
Surfactant Partitioning and Adsorption in Chemical EOR: The Neglected Phenomenon in Porous Media
Authors: Belhaj Ahmed Fatih , Elraies Khaled Abdalla , Sarma Hemanta Kumar , Shuhili Juhairi Aris , Mahmood Syed Mohammad , Alnarabiji Mohamad Sahban
Published: October 2021

During chemical EOR, surfactants encounter significant losses when injected into porous media mainly due to retention. The key mechanisms of surfactant retention are adsorption onto the rock surface and partitioning into the oil phase. The significant losses due to adsorption and partitioning will not only result in poor displacement efficiency but also great financial increased costs. In this review, a comprehensive assessment on the importance of understanding and quantifying surfactant partitioning and adsorption data is presented.

The study explains the surfactant flooding process and the related challenges at harsh reservoir conditions. The surfactant partitioning and adsorption mechanisms throughout the surfactant flooding process, as well as the most influential parameters affecting their behaviors in porous media are comprehensively addressed. Surfactant partitioning and adsorption studies at different operating conditions are then covered considering laboratory, modeling, and simulation studies. Lastly, the measurement procedure and the measurement techniques of surfactant partitioning and adsorption are comprehensively discussed.

Laboratory and simulation studies have concluded that the misinterpretation of surfactant partitioning and adsorption data will affect the main function of surfactants (lowering oil–water interfacial tension). The reported studies have highlighted that surfactant partitioning and adsorption are affected by many factors such as surfactant concentration, pH, salinity, temperature, brine/oil ratio, and rock mineralogy. In contemporary research practice, there is no established method to quantify the surfactant losses due to partitioning in dynamic conditions owing to the occurrence of both adsorption and partitioning simultaneously. However, using static tests, adsorption and partitioning can be distinguished, quantified, and qualitatively verified with dynamic test results. The partitioning effect can be separated, since the test is performed with and without residual oil saturation (oil flood), and by comparing those tests, the effect of partitioning can be detected.

The novelty of this review is based on the importance of understanding the mechanisms of surfactant partitioning and adsorption, which have not been fully covered in the literature. This paper gives more insight into the successful application of surfactant flooding and how it can be optimized with minimal surfactant losses. Findings elucidated in this paper can contribute to minimizing the experimental time and operating cost of future studies in the field of surfactant-based EOR.