bluuebunny/crossref_metadata_2025 huggingface dataset:
Flowback Stimulation of Frac Fluid in Tight Oil Reservoirs Through Supercritical Condition
Authors: Li Ying , Ai Ying , Li Haitao , Chen Mingjun
Published: March 2021

Tight sandstone reservoirs are an important petroleum resources in recent years. Hydraulic fracturing is widely used to stimulate development of tight sandstone oil reservoirs by creating underground fractures, but the low flowback rate of fracturing fluid leads to the water blocking damage and low oil recovery of tight sandstone oil reservoirs compared with those of conventional oil reservoirs. The object of this study is to experimentally investigate the possibility of improving flowback efficiency and oil recovery efficiency through achievement of the supercritical water condition. Self-developed reaction system is used to conduct hydraulic fracturing for tight sandstone samples under both regular and supercritical conditions. While comparing the oil recovery factor and flowback efficiency of the regular and supercritical water hydraulic fracturing, mechanisms behind these results are explored through examination of the change in oil components, the change in rock minerals and the change in pore-fracture distribution. Results show that the dynamic viscosity of the crude oil after the supercritical water hydraulic fracturing is significantly lower than that before hydraulic fracturing, with a decrease of 2.88 mPa·s under ambient condition and a decrease of 0.39 mPa·s under in situ condition. Lighter oil components occupy more percentage of the totoal oil components in the recovered oil from supercritical water hydraulic fracturing than that in the oil recovered from regular hydraulic fracturing, with an average increase of 16% for the oil components of molecular weight from 100 to 200. Heavier oil components of molecular weight larger than 300 have an average decrease of 15.5% after the supercritical water hydraulic fracturing. This indicate the visbreaking of the crude oil under the supercritical water condition. Oil recovery after supercritical water hydraulic fracturing is always higher than that after regular hydraulic fracturing, and the ultimate oil recovery after supercritical water hydraulic fracturing is 66.5% compared with 60% of regular hydraulic fracturing. Fracturing fluid after the supercritical water condition flows much quicker and smoothly than that after the regular hydraulic fracturing, and the ultimate flow back factor of the fracturing fluid is 63% after the supercritical water hydraulic fracturing compared with that of 49% after the regular hydraulic fracturing. Increase in percentage of larger pores/fractures after the supercritical water hydraulic fracturing is more significant than that after regular hydraulic fracturing. The percentage of interstratified illite-montmorillonite decreases an average of 15.2%, while that of kaolinite increase an average of 14.3% in the rock samples after supercritical water hydraulic fracturing compared with the original rock samples. This will benefit the recovery process when oil and water flows together into the well bore after the hydraulic fracturing.
A New Artificial Intelligence Method to Predict Water Flooding Performance in Layered Reservoir
Authors: Chen Cunliang , Han Xiaodong , Zhang Wei , Zhang Yanhui , Zhou Fengjun
Published: March 2021

The ultimate goal of oilfield development is to maximize the investment benefits. The reservoir performance prediction is directly related to oilfield investment and management. The traditional strategy based on numerical simulation has been widely used with the disadvantages of long run time and much information needed. It is necessary to form a fast and convenient method for the oil production prediction, especially for layered reservoir.

A new method is proposed to predict the development indexes of multi-layer reservoirs based on the injection-production data. The new method maintains the objectivity of the data and demonstrates the superiority of the intelligent algorithm. The layered reservoir is regarded as a series of single layer reservoirs on the vertical direction. Considering the starting pressure gradient of non-Newtonian fluid flow and the variation of water content in the oil production index, the injection-production response model for single-layer reservoirs is established. Based on that, a composite model for the multi-layer reservoir is established.

For model solution, particle swarm optimization is applied for optimization of the new model. A heterogeneous multi-layer model was established for validation of the new method. The results obtained from the new proposed model are in consistent with the numerical simulation results. It saves a lot of computing time with the incorporation of the artificial intelligence methods. It showed that this technique is valid and effective to predict oil performance in layered reservoir. These examples showed that the application of big data and artificial intelligence method is of great significance, which not only shortens the working time, but also obtains relatively higher accuracy.

Based on the objective data of the oil field and the artificial intelligence algorithm, the prediction of oil field development data can be realized. This technique has been used in nearly 100 wells of Bohai oilfields. The results showed in this paper reveals that it is possible to estimate the production performance of the water flooding reservoirs.
Downhole Sludge: Formation, Characterization and Removal
Authors: Al-Taq Ali , Al-Moajil Abdullah , Aldarweesh Sajjad , Al-Abbas Hussain
Published: March 2021

Sludge formed downhole in the production interval can be classified into crude oil-based or mud-based sludge. Sludge obstruction may result in partial or total loss of well productivity. Oil-based mud is commonly used in drilling of the pay zones in sandstone formations as a less/non damaging fluid. Oil-based mud typically contain emulsifier, viscosifer and other additives including polymer blend and calcium carbonate to serve different functions. Presence of emulsifier may increase emulsion tendency upon interaction with downhole environment. The resulting emulsion might be tight to an extent that a thick sludge is formed which can impair well productivity. Similarly, oil-based sludge may form from oil/water interaction in presence of emulsifiers, asphaltene, wax, solids, shear, etc. Identification of the sludge material will help in development of an effective chemical treatment to remove formation damage and restore well productivity.

In this study, an extensive laboratory work was conducted to explore potential interactions of different downhole environment contaminants/factors on formation of oil-based and mud-based sludge. Typical mud-based and crude oil-based sludge samples were characterized using different analytical techniques including solvent extraction, XRD, TGA, ICP and viscosity. The results showed that the mud-based sludge sample contained calcium carbonate, dolomite quartz as the main components in the inorganic phase while the organic phase include polymers and oil. The oil-based sludge sample contained mainly water (82 wt%) with some solid particulates and asphaltene in the organic phase. Analysis of supernatants generated from solubility tests conducted for the mud-based and oil-based sludge samples revealed in addition to the high amount of calcium presence of iron in considerable amount (nearly 1,000 mg/L). Interaction of ferric chloride, quartz with an invert-emulsion mud was investigated. A significant increase in viscosity was observed upon incorporation of these contaminates with the mud sample. Iron ions in the aqueous phase tended to stabilized emulsion. This paper presents in detail mechanisms of mud-based and crude oil-based sludge formation upon interaction with environment. It also examined several chemical formulations for removal of mud-based and oil-based sludge samples.
Successful Reinforced Thermoplastic Pipe RTP Insertion for Offshore Application
Authors: Abu Bakar Azlan , Eka Putra I. Wayan , Badaruddin M. Fauzi , M. Ali M. Nazmi
Published: March 2021

Reinforced Thermoplastic Pipe (RTP) design has been improved to meet the very specific requirement of handling corrosive fluids such as crude oil and sour gas up to certain pressure. RTP might have been widely used for onshore application. However, its application as offshore pipeline is not common compared to carbon steel or flexible steel pipeline due to some limitations.

PETRONAS Carigali Sdn. Bhd (PCSB) has undertook a pipeline replacement project at offshore Peninsular Malaysia to reverse flow 17km of existing 12" carbon steel pipeline with 3" Reinforced Thermoplastic Pipe (RTP) pipeline from Platform-A to Platform-B for crude and condensate services. This technology was the first being implemented by PETRONAS and in Asia Pacific region for offshore application.

RTP pipeline was installed from the Shut Down Valve (SDV) of Platform A to SDV of Platform B by insertion methodology into existing 12" carbon steel pipeline. Special inline connectors were used to connect different sections of RTP pipeline, which came in several reels. Specific inspection to be performed at the connection considering the swaging method used and its effect. RTP hang-off and end termination was conducted upon completion of RTP insertion. Specific RTP pre-commissioning and hydrotest procedure was developed and executed with certain acceptance criteria. The pipeline was then commissioned smoothly indicating the successful completion of the project.

It has proven that RTP pipeline insertion for offshore application was technically feasible for a long pipeline. This technology of offshore RTP pipeline provides alternative to the conventional carbon steel pipeline with the advantages of anti-corrosion, high flexibility and low total lifecycle cost.

The aim of this paper is to highlight the analysis and methodology for RTP Pipeline Insertion for offshore application as well as the technical challenges during offshore execution.
Overview the 5 Years Experience of Intelligent Separate-Layer Injection Technology in B Offshore Oilfield
Authors: Liu Yigang , Chen Zheng , Meng Xianghai , Zhang Zhixiong , Zou Jian , Zhang Le , Lan Fei
Published: March 2021

Nowadays intelligent injection is considered as a new frontier for offshore oilfield. In order to improve the water injection indicators such as allocation frequency and qualification rate, intelligent separate-layer injection technology (ISIT) was researched, deployed and optimized in B offshore oilfield from 2015. In the course of 5 years’ project operation, some experience of success or failure was achieved.

B offshore oilfield is the largest offshore oilfield in China with 33 water flooding oilfields and more than 800 water injection wells. With the continuous development, the problem of injection management mainly reflected in the contradiction between increasing demand of allocation and limited operation time and space was exposed. Two kinds of ISIT, cable implanted intelligent separate-layer injection technology(CISIT) and wireless intelligent separate-layer injection technology(WISIT), were deployed to solve the above problem. CISIT controlled the distributor downhole by electricity while WISIT controlled the distributor downhole by pressure pulse. By the use of ISIT, downhole nozzle's action, packer testing and downhole data monitoring could be remotely controlled on the ground. During the 5 years’ test, ISIT was optimized from the field breakdown including large flow range flowing test, cable protection project, efficient coding mode, water seepage resistance and so on. With the continuous optimization and quality control improvement, ISIT has overcome many problems, such as downhole short circuit and communication loss, and is becoming more stable and reliable. At present, ISIT can meet the needs of large flow injection(max 800m3/d per layer) and can adapt to the high frequency of acidizing and fracturing in offshore oilfield. The failure rate of ISIT has dropped to nearly 20% in 2020.

As of December 2020, ISIT has formed series products for different internal diameter wells and applied in 156 water injection wells in B offshore oilfield. The average allocation frequency has increased from less than one time to 2 times per year. Through the application of ISIT, B offshore oilfield has accumulatively saved more than 2100 days of platform occupation and more than 73 million RMB yuan of allocation cost.

The use of ISIT makes B offshore oilfield's injection become more efficient and intelligent. The 5 years’ experience of ISIT applicationin B offshore oilfield has a fairly referential significance for other offshore oilfields.
Ultra-Strong and Catalyst-Free Polycrystalline Diamond Cutting Materials for One-Run-To-TD Game-Changing Drilling Technology
Authors: Zhan Guodong David , Gooneratne Chinthaka , Moellendick Timothy Eric , He Duanwei , Xu Jianhui , Alalsayednassir Alawi
Published: March 2021

Polycrystalline diamond compact (PDC) bits have been increasing their application drilling many formations in the past 20+ years. However, their performance in drilling very hard, abrasive and interbedded formations still needs improvement. The main weak point comes from their primary cutting elements, PDC cutters, which still need improvements of wear resistance, impact resistance, and thermal stability. During the traditional manufacturing of the PDC cutters, cobalt catalyst has to be used to lower the pressure and temperature. In this study, we developed an ultra high pressure and high temperature (UHPHT) technology to make the PDC cutters without metallic catalyst into reality. Through this development, we can generate pressures of 14 GPa-35 GPa, which is three to seven times of that in the traditional PDC cutter manufacturing technology. In addition, the extreme high temperatures ranging from 1,900 °C to 2,300 °C are achieved, which is 500-900 °C higher than that in traditional process. Using this UHPHT technology, we successfully processed ultra-strong and catalyst-free PDC materials with two high pressures at 14 GPa and 16 GPa, respectively, to study the different responses of the material properties from different processing parameters. The new process applied industry available micro-sized synthetic diamond powders as starting material to eliminate the large volume shrinkage in phase transformation from graphite to diamond which is typically experienced in traditional manufacturing process. The hardness of the 14-GPa CFPCD materials reaches the top limit of the single crystal diamond, more than double that of the traditional PDC cutters. The material also possesses the near-metallic fracture toughness – more than two times of the traditional PDC cutters. Furthermore, the 16-GPa CFPCD material breaks all four single crystal diamond indenters in Vickers hardness tester, an indication of the world's hardest material in the family of diamonds. As a result, the material exhibits industry-recorded wear resistance and thermal stability. The combination of these breakthrough properties of the new CFPCD materials activates the goal in the effort of "One-Run-To-TD" in drilling operation, after the implementation of CFPCD materials as PDC cutters for PDC drill bits.
Microbiologically Influenced Corrosion Combined with Under-Deposit Corrosion Mechanism and Control Technology in Water Injection Wells of Middle East Carbonate Oilfield
Authors: Ye Zhengrong , Chi Huachang , Zhou Xiang , Yang Zhiwen , Jiang Weidong , Li Weixiao , Qiu Zhichao , Cui Xiaodong , Chen Guohao , Wang Xiuyun
Published: March 2021

A carbonate oilfield in the Middle East carries out the mixed water injection of produced water and fresh water, after 1 year of its rapid exploration. The injected water is highly corrosive, with high salinity, high chloride concentration and high hydrogen sulfide. Recently, there are dozens of corrosion perforations on L80 tubing in injectors within 2 years in the field and the corrosion rate reaches 3.6 mm/a. After the tubing leaks, the injected water enters into the annulus between the tubing and casing, which causes casing corrosion, damages the well integrity, and greatly influences the field production.

In this paper, the causes for such rapid tubing corrosion failure are investigated by using optical metallographic microscopy, scanning electron microscopy (SEM), energy dispersive spectrometer (EDS) X-ray diffraction (XRD), and combined with the weight loss and bacteria testing. Firstly, test the element composition of the L80 tubing to verify the tubing quality. Secondly, conduct the corrosion experiments of H2S and dissolved oxygen. Thirdly, analyze the morphology and corrosion product composition of failure tubing.

The results indicate that the failed L80 tubing material meets the requirements of API SPEC 5CT-2011 standard. The localized corrosion rate of L80 is 0.293~0.697 mm/a at whole well depth in the simulated injection water. Bacteria were detected in both the injected water and the corrosion products of the failed tubing. In addition, the corrosion products of failed tubing are mainly FeS, CaCO3 and Fe3O4, which indicates that the synergistic effect of microbiologically influenced corrosion and under-deposited corrosion promote the perforation of tubing. Then the corrosion prevention strategy of UHMWPE lined tubing was proposed. UHMWPE lined tubing has been applied in nine water injectors. After one year and a half, one of the water injector’s UHMWPE lined tubing has been detected, no corrosion perforations observed, and the scale deposition became slightly. This case provides useful practical experience for corrosion prevention of high salinity and high acid injection well in carbonate oilfields.
Field Application of Deep Learning for Flow Rate Prediction with Downhole Temperature and Pressure
Authors: Wang Fuyong , Zai Yun , Zhao Jiuyu , Fang Siyi
Published: March 2021

Well real-time flow rate is one of the most important production parameters in oilfield and accurate flow rate information is crucial for production monitoring and optimization. With the wide application of permanent downhole gauge (PDG), the high-frequency and large volume of downhole temperature and pressure make applying of deep learning technique to predict flow rate possible. Flow rate of production well is predicted with long short-term memory (LSTM) network using downhole temperature and pressure production data. The specific parameters of LSTM neural network are given, as well as the methods of data preprocessing and neural network training. The developed model has been validated with two production wells in the Volve Oilfield, North Sea. The field application demonstrates that the deep learning is applicable for flow rate prediction in oilfields. LSTM has the better performance of flow rate prediction than other five machine learning methods, including support vector machine (SVM), linear regression, tree, and Gaussian process regression. The LSTM with a dropout layer has a better performance than a standard LSTM network. The optimal numbers of LSTM layers and hidden units can be adjusted to obtain the best prediction results, but more LSTM layers and hidden units lead to more time of training and prediction, and LSTM model might be unstable and cannot converge. Compared with only downhole pressure or temperature data used as input parameters, flow rate prediction with both of downhole pressure and temperature used as input parameters has the higher prediction accuracy.
Pre-Drilled ECD Design by Using Fracture Pressure Model in Satun-Funan Fields, Pattani Basin, Gulf of Thailand
Authors: Kananithikorn Nardthida , Songsaeng Teenarat
Published: March 2021

Lost circulation is the most common drilling issue for infill drilling projects in Satun-Funan Fields, South Pattani Basin, Gulf of Thailand (GOT). The depleted sand is possible to be a root cause in many wells based on observation from resistivity time-lapse separation in depleted sands or shale nearby. Therefore, the objective of this study is to estimate fracture pressure related to the depleted sand and design an appropriate Equivalent Circulating Density (ECD) threshold for each well to avoid or minimize lost circulation and well control complication during drilling a new well.

This study model is using Eaton (1969) equation. There are 3 input parameters which are Poisson's Ratio and pre-drilled estimated depletion pressure and depth. With limitations of no actual fracturing data and limited sonic log, the maximum ECD while lost circulation reading from Pressure While Drilling (PWD) tool and formation pressure test data were used to back-calculate for Poisson's Ratio and identified a relationship with depth. From the total of 68 wells in the Satun and Funan areas, the interpreted Poisson's Ratio ranges from 0.36 to 0.44 and its linear trend is apparently increasing with depth. To minimize the variation of back calculated Poisson's Ratio the local data become an important key for model validation and maintain the similarity of subsurface factors. This interpreted Poisson's ratio trend will be used to calculate for fracture pressure by incorporating with estimated depletion pressure and depth that expect to encounter in each planned well. The lowest fracture pressure in a planned well is used to prepare pre-drilled ECD management plan and a real-time well monitoring plan. Additionally, the model can be adjusted during the operational phase based on the new drilled well result.

This alternative model was applied in 4 trial drilling projects in 2019 and fully implement in 6 drilling projects in 2020. The lost circulation can be prevented with value creation from expected gain reserves section is $57M and cost avoidance from non-productive time due to lost circulation is $3.4M. With an effort, good communication and great collaboration among cross-functional teams, the model success rate increases by 12%. However, there are some unexpected lost events occurred even though the maximum ECD lower than expected fracture pressure. This suspect as a combination of limitations and uncertainties on key input parameters and drilling parameters.

In the future, the model is planned to expand to other gas fields in the Pattani Basin which will move to more infill phase and have higher chance of getting lost circulation to maximize benefits as the success case in Satun and Funan fields.
A Case Study on Chemical Free System for Crude Sweetening: A first in Indian Offshore; Design Challenges and Post Installation Performance Evaluation
Authors: Gupta M K , Singh V K , Sharma MSK , Katre N V , Boddu V , Nath Siddharth Priya , Reddy Rajesh , Raman Ravi
Published: March 2021

In a producing field of western offshore, H2S content in oil was found to be in the range of 3000-5000 ppm against the desired level of 200ppm. High H2S concentration posed a serious threat to pipelines integrity and downstream equipment. Mitigation by conventional means such as chemical injection is generally avoided at offshore due to constraint like continuous pumping, storage of chemicals, frequent monitoring, logistical impediments and disposing off by-products in compliance with statutory requirements. Considering many limitations at offshore, an approach was adopted for reduction of H2S utilizing Henry's principle which states that the amount of dissolved gas in a liquid is proportional to its partial pressure. Reducing the partial pressure by utilizing sweet natural gas or some other inert gas, H2S can be removed. Same principle was applied to conceptualize a processing system wherein sour crude can be sweetened to the desired level utilizing sweet gas as stripping gas. Processing System was designed considering many downstream and upstream constraints in the existing system and without any rotating and heating requirement. Unlike conventional way of sweetening such as chemical injection which requires continuous dosing of chemical and disposing off by-products in compliance with statutory requirements and hence, found not feasible at offshore to sweet enormous amount of crude. The designed processing system, a first in Indian offshore environment, is commissioned at one of the offshore complex and has proved it efficacy wherein H2S content of around 3000 ppm in around 6000 barrel/day of crude is being reduced to less than 10 ppm level without use of any hazardous chemicals and without any need of rotating and heating equipment's and with minimum maintenance and manual intervention requirement. The system has lowest operating cost, low maintenance and without use of any rotating and heating equipment's and hence can be emerged as an ideal solution for crude oil sweetening at offshore environment or in an environment where bare manual intervention is required.
Seismic Data Processing and Depth Imaging for Yingxionglin Complex Structures-Belt in Qaidam Basin, Tibetan Plateau
Authors: Wang Yongsheng , Tan Chenqing , Zhu Bo , Tong Yanming , Wang Haifeng , Wu Chuan , Dong Yongcang , Li Rong
Published: March 2021

The Yingxionglin structural belt located in the world's highest-altitude petroliferous basin, Qaidam Basin. Due to its complex surface condition, subsurface structure and low signal-to-noise ratios (SNR) of seismic data, exploration and production is quite challenging. From 2012 to now, we continued developing and improving seismic data processing and interpretation workflow. After several rounds field support and testing, new techniques exploring and velocity modelling iteration, we gradually developed a suitable workflow for complex dipping structure imaging including signal processing, velocity modeling, and depth migration. The quality of final delivered 3D seismic data is significantly improved with the integrated static correction techniques, fidelity multi-domain noise attenuation, 5D MPFI regularization, integrated velocity modelling and final pre-stack depth migration. According to our final deliverables, we identified credible traps and high-production reservoirs were found.
Factors Controlling Porosity Permeability Relationship for Reservoir Quality Prediction: A Case Study of Malay Basin Reservoir, Malaysia
Authors: Kasim Fadzlin Hasani , Kantaatmadja Budi Priyatna , Wan M Zainudin Wan Nur , Ali Amita , Ismail Hasnol Hady , Ahmed Siddiqui Numair
Published: March 2021

Predicting the spatial distribution of rock properties is the key to a successful reservoir evaluation for hydrocarbon potential. However, a reservoir with a complex environmental setting (e.g. shallow marine) becomes more challenging to be characterized due to variations of clay, grain size, compaction, cementation, and other diagenetic effects. The assumption of increasing permeability value with an increase of porosity may not be always the case in such an environment. This study aims to investigate factors controlling the porosity and permeability relationships at Lower J Reservoir of J20, J25, and J30, Malay Basin.

Porosity permeability values from routine core analysis were plotted accordingly in four different sets which are: lithofacies based, stratigraphic members based, quartz volume-based, and grain-sized based, to investigate the trend in relating porosity and permeability distribution. Based on petrographical studies, the effect of grain sorting, mineral type, and diagenetic event on reservoir properties was investigated and characterized. The clay type and its morphology were analyzed using X-ray Diffractometer (XRD) and Spectral electron microscopy.

Results from porosity and permeability cross-plot show that lithofacies type play a significant control on reservoir quality. It shows that most of the S1 and S2 located at top of the plot while lower grade lithofacies of S41, S42, and S43 distributed at the middle and lower zone of the plot. However, there are certain points of best and lower quality lithofacies not located in the theoretical area. The detailed analysis of petrographic studies shows that the diagenetic effect of cementation and clay coating destroys porosity while mineral dissolution improved porosity. A porosity permeability plot based on stratigraphic members showed that J20 points located at the top indicating less compaction effect to reservoir properties. J25 and J30 points were observed randomly distributed located at the middle and bottom zone suggesting that compaction has less effect on both J25 and J30 sands. Lithofacies description that was done by visual analysis through cores only may not correlate-able with rock properties. This is possibly due to the diagenetic effect which controls porosity and permeability cannot visually be seen at the core. By incorporating petrographical analysis results, the relationship between porosity, permeability, and lithofacies can be further improved for better reservoir characterization.

The study might change the conventional concept that lower quality lithofacies does not have economic hydrocarbon potential and unlock more hydrocarbon-bearing reserves especially in these types of environmental settings.
An Innovative Approach to P&A Barrier Verification and Cement Plug Placement Utilising In-Situ Completion Strings: A Case Study
Authors: Imrie Andrew , Kamaludin Ashikin , Hood Andrew , Agnew Alistair
Published: March 2021

Traditional evaluation of behind-casing cement bond quality prior to cement plug placement involves removal, storage, transportation, and disposal of the tubing completion string. This paper presents an innovative approach to verifying cement bond and subsequent cement plug placement. This method involves cutting and retrieving part of the completion string and deploying acoustic logging tools into the casing, followed by using the tubing as a cement stinger.

The procedure described in this paper first involves plugging and cutting the tubing, followed by partial retrieval of the completion to expose the abandonment horizon, which may be an impermeable shale or salt layer. A radial cement bond log tool is conveyed on wireline out of the tubing cut in order to evaluate the cement bond behind the exposed casing section. The existing cement sheath is assessed in accordance to a cement evaluation criteria to determine suitability as a barrier. A balanced cement plug is pumped utilising the existing completion string rather than a dedicated stinger. The permanent barrier is then verified appropriately based on satisfying key metrics in the pumping operation before hanging off the completion tubing in-hole and progressing with the rest of the abandonment programme.

In the case study presented here, the tool string design considered the need to pass completion restrictions, convey through production tubing, and remain centralised with up to 50-degree deviation. Analysis of cement bond log data indicated that bond quality was good and suitable to place an internal cement plug across the abandonment horizon. This satisfied a minimum of 200-ft coverage across the zone of interest. The existing deep-set mechanical plug placed in the tubing prior to tubing cut was utilised as a base for the cement barrier. A 2,000-ft balanced cement plug was successfully set across the zone of interest. The completion tubing was used as a conduit for cement slurry placement, eliminating the usage of a dedicated work string. At the end of displacement, the tubing string was pulled out of hole safely to approximately 500-ft above the top of the cement with the help of controlled-gel progression properties incorporated in the slurry design. Due to existing completion accessories, setting a through-tubing cement plug and tubing rotation is not an option. Expandable cement was pumped to mitigate natural shrinkage and enhance post-set cement expansion to ensure a competent barrier. The cement job objectives were achieved by meeting the cementation execution criteria with no requirement to wait on cement. This provides additional time saving to the well abandonment.

The discussed approach has successfully realised a significant rig-time saving of approximately two days on each well. Going forward, the methodology has effectively been applied to multiple wells across the Southern North Sea (SNS).
The Transient Dynamics of Permanent Fiber Temperature Analysis and Downhole Gauge Evaluation of an Acid Stimulation Job in a Brown Field, Offshore Malaysia
Authors: Ting Chang Siong , Minggu Nur’ain , Kamat Dahlila , Riyanto Latief , Tan Chee Seong , Kalidas Sanggeetha , Kamarulzaman Ammar , Goh Gordon Kim
Published: March 2021

Well B-2 is a dual-string producers with Distributed Temperature Sensing (DTS) fiber installed along the long string (i.e. Well B-2L) across the reservoir sections. Each zone comprises of sub-layers. This system enabled the operator to continuously monitor the wellbore temperature across all the producing intervals including gas-lift monitoring, well integrity identification, zonal inflow profiling and stimulation job evaluation. This paper mainly discusses the post matrix acid stimulation job with interpreted DTS and zonal Permanent Downhole Gauge (PDG) data.

Well B-2L has been selected for matrix acidizing treatment to improve the productivity due to potential formation damage, proven by the declining production over the years. Prior to the execution of the acidizing job, several conformance jobs such as injectivity test, tubing pickling were performed. This is followed by the main acid treatment and flow back. DTS & zonal PDG data were acquired throughout the operation. A transient simulator model was built incorporating all the reservoir properties including well trajectory and completion schematic to analyze the DTS profile and understand the zonal inflow profiling for each zone post treatment. A baseline temperature was acquired for the geothermal evaluation. The DTS data has been studied according to actual event schedules. Some significant findings are; i) completion accessories effect (feedthru packers) creates temperature anomalies, ii) leak points detected at top producing zone signifies cooling effect due to injected fluid. The main treatment was intended at zone 2 and 3 using nitrified acid. However, leak points at top zone caused bypassed injection into Zone 1 and 2 instead. Fiber optic DTS warmback profiles post main-treatment was analyzed to quantify the fluid intake from sub-layer in each zone.

Qualitatively from the DTS-interpreted zonal profiling, the data clearly shows most of treatment fluid is being injected into Zone 1 and 2 with no intakes at Zone 3. Furthermore, warmback analysis confirmed the high intake zones from sub-layers within the main zone based on the permeability contrast. This paper will further discuss the zonal injectivity understanding for improvement from the zonal-inflow profiling evaluation by incorporating DTS, PDG and surface production data.
Applications of a Novel Lost Circulation Additive
Authors: Zhu Qi
Published: March 2021

Lost circulation is a complicated situation in the drilling operation, wasting a lot of time and mud during processing. A serious lost circulation can cause hazards, such as sticking, blowout and collapse of well. There are some problems in conventional plugging technology, such as particle size of plugging material does not match crack width, slip of the blocking zone, and weak adhesion of lost circulation additive to the rock, which restricts the success rate of lost circulation operation.

Regular and elastic polyhedron structure material compounds elastic variable network plugging material and rigid plugging materials to form a loss circulation materials (LCM)plugging mixture for different leakage speed and crack width affected by stress.

Through plugging and HTHP sand bed experiment loss circulation materials(LCM) and amount of gel were optimized and improved. Through indoor simulation about leakage process of different leakage speed and different crack sizes, the on-site construction formula suitable for wells under different temperature is formed and determined.

Scanning electron microscope shows the plugging gel has a variable network structure. By changing the ratio of elastic plugging material, rigid plugging material and gel, a LCM plugging formula for high temperature and high pressure formations can be formed to meet the pressure requirement of 7.5MPa. Leakage simulation formed on-site plan under different leakage rate to adapt to 180°C.

The novel CPM material has been well-field tested and used for HPHT reservoirs. When the rate of leakage less than 30 m3/h and 30-60 m3/h, success rate of single plugging is more than 95% and rate of leakage greater than 60 m3/h success rate of single plugging beyond 80%. Leakage loss time is more than 80% shorter than conventional plugging techniques.
Peripheral Low Salinity Water Injection Handil Case Study
Authors: Sianturi Julfree , Handoko Bayu Setyo , Suardiputra Aditya , Senoputra Radya
Published: March 2021

Handil Field is a giant mature oil and gas field situated in Mahakam Delta, East Kalimantan Indonesia. Peripheral Low Salinity Water injection was performed since 1978 with an extraordinary result. The paper is intending to describe the success story of this secondary recovery by low salinity water injection application in the peripheral of Handil field main zone, which successfully increased the oil recovery and brought down the remaining oil saturation beyond the theoretical value of residual oil saturation number.

Water producer wells were drilled to produce low salinity water from shallow reservoirs 400 - 1000 m depth then it was injected to main zone reservoirs where the main accumulation of oil situated. This low salinity water reacted positively with the rock properties and in-situ fluids which was described as wettability alteration in the reservoir. It is related to initial reservoir condition, connate water saturation, rock physics and connate water salinity. This peripheral scheme then observed having the sweeping effect on top of pressure maintenance due to long period of injection.

The field production performance was indicating the important reduction of residual oil saturation in some reservoirs with continuous low salinity water injection. From static Oil in Place calculation, some reservoirs have high current oil recovery up to 80%. This was proved by in situ residual oil saturation measurement which was performed in 2007 and 2011. It was indicating the low residual saturation as low as 8% - 15%. This excellent result was embraced by a progressive development plan, where water flooding with pattern and chemical injection will be performed later on.

The continuation of this peripheral injection is in an on-going development with patterns injection which is called water flooding development. An important oil recovery can be achieved with a simple scheme of low salinity injection, performed in a close network injection, where the water treatment is simple yet significant oil gain was recovered. This innovation technique brings more revenue with less investment compared to chemical EOR injection.
Toward Developing Non-Corrosive Acid System for Complex Scales Removal
Authors: Gamal Hany , Elkatatny Salaheldin , Al-Afnan Saad , Bahgat Mohamed
Published: March 2021

Oil and gas industry deals with fluid streams with different ions and concentrations that might cause scale precipitation. The scale precipitation, will thereafter, affect the fluid flow characteristics. Many problems will be raised by the scale deposition that affects the overall petroleum production.

This paper aims to develop a non-corrosive acid system with high dissolution efficiency for field complex scales. The paper provided a series of lab analysis that covers the compositional analysis for the collected scale sample, and evaluating the developed acid system for compatible and stable properties, dissolution efficiency, and the corrosive impact. A field scale sample that has a composite chemical composition of calcium carbonate, calcium sulfate, kaolinite, barium sulfate, magnetite, and halite with different weight percentages by employing the diffraction of X-ray technology.

Developing the new scale dissolver was achieved by specific compositional study for the organic acids to achieve high dissolution efficiency and low corrosive impact for the field treatment operations. The study results showed the successful scale removal for the developed dissolver at 160 and 210 °F by dissolution efficiency 100 % for 5 hours. The fluid showed a stable and compatible performance with low rate of solids precipitation after the scale treatment (2.3 %). The developed dissolver has a pH of 9. The corrosion test was conducted without any scale inhibitors and the results showed the low corrosion effect by 0.0129 lbm/ft2. The obtained successful results will help to dissolve such complex field scales, maintain the well equipment, and maintain the petroleum production from scale issues.
Navigating the Depleted Fracture Gradient During Operations: From Concept to Drilling, Open Hole FIT Management & Cementing
Authors: O'Reilly Gerard , Chan Alvin W.
Published: March 2021

Depleted Fracture Gradients have been a challenge for the oil and gas industry during drilling and cementing operations for over 30 years. Yet, year after year, problems related to lost circulation, borehole instability (low mud weight due a low fracture gradient), and losses during cementing operations leading to NPT and remedial work continue to rank as some of the top NPT events that companies face. This paper will demonstrate how the geomechanical modeling, well execution and remedial strengthening operations should be implemented to provide for a successful outcome. The use of a Fracture Gradient (FG) framework will be discussed, and the use of a negotiated fracture gradient will highlight how the fracture gradient can be changed during operations. This paper will also show actual examples from Deepwater operations that have successfully executed a detailed borehole strengthening program. Through our offset studies and operational experience, we will provide a format for navigating complex depleted drilling issues and show an example on recovering from low fracture gradients.

This paper will demonstrate (1) how our framework facilitated multi-disciplinary collaborative discussion among our subsurface and well engineering communities; (2) how the impacts of drilling fluids and operational procedures can change this lost circulation threshold; and (3) how our negotiated FG approach has successfully delivered wells drilled in narrow margins.
Autonomous Inflow Control Valve Applications Creating Better Wells: A Review of Design Optimization and Associated Benefits
Authors: Abd El-Fattah Mahmoud , Fahmy Ahmed Moustafa , Wahaibi Hamed , Shibli Abdullah , Zuhaimi Khaled
Published: March 2021

One of the largest oil fields in the GCC was developed in the 1960's. The field was initially produced under natural depletion supplemented by gas injection. The high offtake rates led to a rapid displacement of the gas/oil contact; thus, the field has now been suffering from early gas/water breakthrough and uneven fluid influx along with the horizontal wells. The reservoir has been on production for more than 50 years. Water/gas breakthrough from fractures being the major challenge which negatively affects wells oil production rates. Applying technology which can manage water/gas breakthrough in a cost-effective manner whilst allowing increased oil production was a key goal from operators in this field.

Passive Inflow Control Devices (ICD) were introduced to the global oil and gas market in mid/late-1990's, and the first generation of Autonomous ICD (AICD) that can help reduce more unwanted gas or water was first installed in 2007. ICD's successfully demonstrated that they could delay the gas and/or water breakthrough within horizontal wells, but they could not choke gas when the coning/gas-breakthrough occurred and along with limited abilities to stop unwanted water production. To help solve this problem, the Autonomous Inflow Control Devices (AICD-RCP) with a movable disc was introduced to the market and demonstrated reduction of gas production by 20-30% with similar gains in oil production[1]. In this paper, the newest generation of Autonomous Inflow Control Valve (AICV) technology is presented. The AICV technology has a movable piston that can close and reduce the unwanted gas and water production by up to 95%[2]. The application of AICVs discussed herein were deployed within several wells which had extremely high Gas Oil Ratio (GOR) and low oil production. The novel AICV technology can differentiate between fluid types based on viscosity and density. When undesired fluid (gas and/or water) starts to be produced, the AICV chokes the valve flow area gradually until completely shutting off, all without well intervention[3].

Well production performances are documenting the benefits of installing AICV completions. The results demonstrate the AICVs closing the zones with high gas production and favoring oil-rich zones. Majority of evaluated wells demonstrated clearly that the extremely high GOR was reduced; some wells have returned to solution GOR for more than two years, and at the same time, the daily oil production is increased.
A New Methodology for Calculating Wellbore Shut-in Pressure in Numerical Reservoir Simulations.
Authors: Kayode Babatope , Jamiolahmady Mahmoud
Published: March 2021

In low permeability reservoirs, the pressure transient response of the build-up takes a long time to stabilize. During the history matching process, the observed non-stabilized build-up pressure cannot be compared to simulated well block pressure (WBP). This challenge arises because most reservoir simulators convert the WBP of flowing wells to wellbore pressure using Peaceman’s equation, but do not perform this conversion for build-up pressure data. Such conversion is particularly important for low permeability reservoirs. This paper discusses a new method to calculate the wellbore pressure of shut-in wells and highlights its benefits.

A full superposition equation for analytical wellbore-pressure, without the usual logarithmic approximation of Ei function, is the basis of the mathematical formulation proposed here. A modified equivalent radius concept together with the superposition principle are used to arrive at an expression to calculate numerical wellbore pressure from simulated WBP. To verify the validity of the approach, the calculated numerical wellbore pressure data is compared with analytical wellbore pressure build-up data described by the Horner function.

The results show that numerical wellbore pressure is in better agreement with the non-stabilized observed pressure data than WBP. This is because WBP is an average pressure over a spatial distance in which theoretical pressure varies as a logarithmic function of distance. Therefore, when the grid size is large and spatial pressure gradient is significant (as the case in low permeability reservoirs), simulated shut-in WBP may be very different from observed shut-in wellbore pressure measured by a downhole gauge. Our results demonstrate that this difference increases with increasing grid size. If, during numerical well testing, numerical wellbore pressure is used for the log-log pressure derivative plot instead of WBP, the early distortions of infinite acting radial flow (IARF) stabilization, which has been observed by some investigators is eliminated.

In summary, the presented methodology to calculate shut-in wellbore pressure is practically attractive to complement existing simulator capabilities for relating wellbore pressure to well block pressure. The use of numerical wellbore pressure instead of WBP, which is currently used, eliminates the need to apply the time-shift proposed by some investigators to correct IARF signature deviation, and observe the true flow regime.