bluuebunny/crossref_metadata_2025 huggingface dataset:
Wettability State and Phase Distributions during Steam Injection with and without Chemical Additives: An Experimental Analysis Using Visual Micro-Models
Authors: Pratama Randy Agra , Babadagli Tayfun
Published: October 2019

Our previous contact angle measurements showed that phase change plays an essential role in wettability, thus impacting heavy-oil recovery. While oil is the strongly wetting phase in the steam zone, it becomes the opposite in the condensation (hot-water) zone—regardless of temperature. We also showed that the reverse wettability can be changed using new generation chemicals including thermally resistant chemicals (special surfactants, alkalis, water soluble solvents, and ionic liquids). Even though they reveal useful information, contact angle measurements are limited in accounting for the importance of the wettability alteration effect on the phase distribution/entrapment and oil recovery. Micromodel studies are then preferred to assess these characteristics.

All observations and measurements in this research were conducted at temperatures up to 200°C on glass bead micromodels. The models were initially saturated with brine solution and then displaced by two types of mineral oils (450 cP and 111,600 cP at 25°C) to maintain initial water and oil saturation. Hot-water was then constantly injected into the micromodels to evaluate the impact of phase change and wettability status on residual saturation development. Similar parameters were also evaluated in pure steam injection by elevating the temperature to match the steam temperature and maintaining pressure below saturation pressure. Next, several chemical additives screened from the previous contact angle and thermal stability measurements were introduced during both hot-water and steam applications to observe their ability in modifying phase distribution, wettability state, and oil recovery at different pressures and temperatures.

The result of the experiments in the glass bead micromodel presented that phase distribution and wettability state were sensitive to steam phase (vapor yielded oil-wet or condensate yielded water-wet case). This phenomenon also aligned with the previous hypotheses indicating that phase change has an impact on the wettability state and residual oil saturation. At any circumstances, wettability alteration with chemicals was possible with the anionic surfactant and SiO2 nanofluid. The shape and characteristics of the trapped oil with and without chemicals were identified through micromodel images and suggestions were made as to the conditions (pressure, temperature, and time to apply during the injection application) at which these chemicals show optimal performance.

Study and analysis of phase distribution and wettability change in micromodels during hot-water and steam applications provide useful data and understanding of interfacial properties, oil trapping mechanism, and recovery performance of rock/bitumen/hot-water or steam system in the reservoirs. For practitioners, chemical additives were recommended, validated by visual images and thermal stability tests.
Improvement of Operational Excellence: Reducing Unplanned Production Deferment
Authors: Lim Jit Sen , Kueh Jing Zhi , Maskawi Bolhi
Published: October 2019

In the upstream oil and gas production sector, unplanned production deferment (UPD) is defined as the conduit production flow deviation from technical potential due to unscheduled interruptions. Low UPD is a key indicator of a facility's operational excellence. High UPD reflects that a facility is facing frequent downtime of critical equipment, poor work schedule planning and execution, under-performing producer wells, inability to meet the facility's production targets, increased expenditure, as well as possible additional work-related stress among the employees. In this case study, UPD of a Malaysian upstream brownfield production facility is mostly affected by wells-related (33%), process-related (31%), and rotating equipment (25%). A clear framework has to be in place to resolve and address the UPD, with improvement recommendations detailed out for deliberation. The outcomes of UPD reduction efforts heavily depend on the integration as well as collaboration of people, processes and technology.
A Modified Embedded Discrete Fracture Model to Improve the Simulation Accuracy During Early-Time Production of Multi-Stage Fractured Horizontal Well
Authors: Rao Xiang , Cheng Linsong , Cao Renyi , Jia Pin , Dong Peng , Du Xulin
Published: October 2019

This paper pointed out that the simulation accuracy of original embedded discrete fracture model (EDFM) during early-time production of multi-stage fractured horizontal well is low due to the linear pressure distribution assumption in matrix cells containing fracture cells. To resolve the above limitation of original EDFM, a modified EDFM is presented by adding multi-layer virtual cells adjacent and parallel to fracture cells and changing the connections between cells. This modified EDFM can make the same function like LGR technique, and does not bring any complexity to pre-processing algorithm of EDFM, especially for its 3D implementations. A test case and an application example for complex fracture network are implemented to verify that this modified EDFM can significantly improve the early-time simulation accuracy to greatly eliminate the errors of the original EDFM.
Highly Efficient Nanocrystalline Cellulose Cross-Linker for Fracturing Fluid System
Authors: Zhang Chuanbao , Wang Yanling , Forson Kobina , Yin Zichen , Guo Baoyu , Liu Junyi
Published: October 2019

Guar gum and its derivative based-gels cross-linked with boron have been used in hydraulic fracturing for decades. In order to achieve gel strength requirements, conventional fracturing requires the use of a large amount of thickener and cross-linking agent, which results in more residue and difficulty in the recovery of permeability. At the same time, the gel can be used to achieve the best thermal stability in a high pH environment. Therefore, we proposed a highly efficient organoboron nanocellulose cross-linker for low polymer loading fracturing fluids.

Nanocrystalline cellulose (NCC) resulted from sulfuric acid hydrolysis of cellulose microciystalline. Boron-modified nanoparticles were synthesized by one-pot reaction as nano boron cross-linker (NBC). Nanocrystalline cellulose (NCC), (3-Aminopropyl) triethoxysilane, Organic boron (OBC) was mixed at a ratio of 1:4:4 and stirred at a constant temperature of 85°C for 5 hours. The presence of surface modification was shown with FTIR spectroscopy and the particle size was characterized by Transmission Electron Microscopy. The microscopic morphology of the NBC crosslinked gels was observed by SEM. The changes in gels rheology in different pH environments were investigated. In addition, the effect of mass ratio of NCC and OBC on the rheological properties of NBC crosslinked HPG gel was also investigated.

The results of FTIR spectroscopy illustrated OBC was bonded onto the surface of NCC by B-N bond. The particles have a large aspect ratio with a diameter of 5-20 nm and a length of 50-300 nm. NBC cross-linked 0.25 wt.% gels exhibited excellent rheological properties at 90°C. When the pH was increased from 7 to 11, the viscosity of the NBC crosslinked gels increased from 56.64 mPa·s to 348.7 mPa·s, and as the pH continued to increase, the viscosity of the gels began to decrease. The gels maintained a shear rate of 170s-1 at 90°C and the residual viscosity after shearing for one hour was higher than 50 mPa·s, which is in accordance with the requirements of fracturing construction. Due to the thermal stability of the NBC cross-linked-gels, pH was affected. The NBC cross-linked-gels had different microscopic morphology at different pH and the microstructures become more complex at higher pH.

NCC is a kind of natural macromolecular materials made from microcrystalline cellulose, which has the properties of abundance, biodegradability and low price, and has greater economic advantages compared with other nanoparticles. The NCC prepared by sulfuric acid hydrolysis has good dispersion due to electrostatic repulsion. The NBC crosslinker has excellent cross-linking properties, which may provide a possible solution to reduce the amount of cross-linking agent used, thereby reducing formation damage.
Unlocking Depleted Sandy Reservoir Potential using ESP Improvement in Cinta Field
Authors: Herlanda Maulidia , Afi Futiha Nur , Dondo Maximilian Stef , Zhafira Kautsar , Bagus Satrio Sumatri Anggi
Published: October 2019

The Cinta Field is one of fields in Offshore South East Sumatera Block which discovered on 1970. The first well development was in 1971 in Talang Akar Formation (TAF) which consist of Zelda and Gita member. Peak production was 70,721 barrel oil per day on Jan, 1977. Initial reservoir pressure was 1488 psi and current reservoir pressure is 500 psi. Nowadays, Cinta field has produced 4,300 barrel oil per day and average water cut 96%. The production challenges in TAF are depleted reservoir pressure that leads to sand and gas production. Artificial lift method applied in Cinta Field is Electric Submersible Pump (ESP).

Sand production can create problem in ESP that lead to trip off overload or the worst is shaft broken. Loss of production due to waiting barge to replace the broken ESP will occur. Mechanical sand control has been applied such as gravel pack, expandable sand screen and standalone sand screen to prevent sand produced through ESP. Most of them have failed due to massive sand production. Re-sand control can be alternative solution for this problem, but it can't be done due to low reservoir pressure and most of sand control will lowering productivity index of the wells. Immediate solution of this situation will be improvement of ESP itself. ESP will adapt with sand production situation by improving material and design of pump stages.

This paper will present improvement run life of ESP by using new type ESP that is more suitable in sand production situation in Cinta Field.
Best Practices for Assessing Chemical EOR Project Risks for a Major Malaysian Offshore Oilfield
Authors: Khanifar Ahmad , Deo Tewari Raj , Mousavimirkalaei Seyed Mousa , Bin Abd Raub Mohd Razib
Published: October 2019

A major Malaysian matured offshore oilfield which is currently under waterflooding has been seen declining in production in recent years. Among various enhanced oil recovery (EOR) techniques evaluated, this field appears to be amenable to chemical EOR implementation. Chemical EOR project requires high capital and operating expenditure (CAPEX and OPEX) and often involve complex logistical and operational challenges in an offshore environment. A comprehensive study and technical road map plan from laboratory to pilot and then to full field reservoir simulation model has been established to reduce the project risks prior to field-scale chemical EOR implementation.

For this study, detailed EOR screening and ranking evolution is conducted and confirmed that chemical EOR is ranked high among other EOR techniques and stands for better chance of success techno-economically. Subsequently, all the relevant field examinations to verify the incremental oil recovery from chemical EOR including extensive laboratory experiments such as fluid-fluid and fluid-rock evaluations and pilot tests by single well chemical tracer method were designed and implemented.

This paper mainly presents the challenges and the strategies to build a realistic full field chemical EOR numerical simulation model (using CMG's STARS), which include history matching and waterflooding optimization process stages. The work has been carried out to address the best practice workflow for chemical EOR simulation, lessons learned from how to properly prepare and incorporate the chemical input data, identify uncertainties relate to project risks and minimize or mitigate the impact of risks to the project economics.

Numerical simulation was utilized along with assisted optimization methods that combine experimental design and artificial intelligence (AI) techniques (using CMG's CMOST) to determine injection chemical concentration and chemical slug size for optimal oil recovery factor and project net present value (NPV). Sensitivity studies were also performed with the reservoir simulation models to determine the impact of effects such as residual oil saturation (Sor) reduction, chemical loss through adsorption, dilution effects on capillary number, salinity and viscosity effects, cooling effects, chemical reactions, among others. The study results show that chemical EOR injection is a technically feasible and economically viable option for this oilfield from subsurface, incremental oil recovery, and facilities stand points. Furthermore, the results of this risk assessment will facilitate and expedite the full field project execution and investment plan in future.
A New Artificial Intelligence Recognition Method of Dominant Channel Based on Principal Component Analysis
Authors: Chen Cunliang , Han Xiaodong , Yang Ming , Zhang Wei , Wang Xiang , Dong Peng
Published: October 2019

Long term waterflooding leads to the formation of dominant channels in sandstone oil reservoirs, which aggravates the heterogeneity of the reservoir and decreases the displacement performance of the injected water. The ineffective water circulation through the dominant channel would significantly increase the cost of water injection and reduce the oilfield exploitation effciency. Therefore, valid identification and controlling of the dominate channel are essential for enhancing the oil production efficiency of waterflooding reservoirs. Although many methods have been proposed to identify the dominant channel, the accuracy of these methods is always unsatisfactory caused. The results obtained by using various methods are not consistent with the others.

A new method that can comprehensively utilize multiple data is proposed here for improving the identification accuracy of dominate channels. The formation of the dominant channel is affected by both geological factors and development factors. And all these parameters change during the waterflooding process and could reflect the formation of dominant channels. In our method, the evaluation index system consisted of both geological factors and development factors that are firstly formed and analyzed. Consequently, the principal component analysis (PCA) method is applied to aggregate the multiple independent indexes into a comprehensive index. The calculated relative value of the comprehensive index is then considered as the assessment criterion to identify the dominant channel. As an artificial intelligence method, PCA is widely used for reducing dimension statistics. This method has good advantages in the identification of the dominant channel since it can take various data into consideration and reduce subjectivity during the identification process.

The proposed method has been applied in several oilfields for dominant channel identification, and the results are entirely satisfactory. Accurate identification of dominant channels is helpful for the design of an effective adjustment plan, which could provide technical support for achieving higher production efficiency and better economic benefits.
Confirmed Effectiveness of Tracers’ Production Logging in Comparison with Conventional Production Logging
Authors: Basov Artem , Bukov Oleg , Shevchuk Taras , Lazutkin Dmitry , Saprykina Kseniya , Kiselev Vasily , Novikov Igor , Drobot Albina
Published: October 2019

Due to traditional oil and gas reserve depletion, the share of unconventional, hard-to-recover oil and gas reserves is constantly expanding. The cost of horizontal well stimulation used to increase oil recovery rate using multi-stage hydraulic fracturing is significantly higher. Addressing this requires the implementation of new technologies and services to facilitate optimal drilling, completion and stimulation returns, thus shifting the focus to analyzing well productivity increases. The use of developed production logging technology allows oil and gas producing companies to efficiently determine well productive intervals, thereby indicating high production rates and maintaining the profitability of operating wells by eliminating non-productive intervals. This data allows for planning field development with higher profitability by increasing the oil recovery rate.
An Integrated Geological Approach for a Successful Waterflood Implementations and EOR Planning: Lesson Learned from T Field Development, Barito Basin, Indonesia
Authors: Setya Wardhana Brianto Adhie , Titaley Grace Stephani , Purwatiningsih Ninik
Published: October 2019

The brain of a waterflood project is a geological framework that defines reservoir continuity relative to its transmit fluids as well as restrict fluid movement. The lack of geological knowledge results in the misleading interpretation and understanding of the reservoir behavior. This paper presents an integrated geological aspect, concept and approach to design an effective well pattern and well spacing in waterflooding. This method is proven to improve sweep efficiency and lead us to make an EOR planning in our field. T Field is one of the mature fields where a successful waterflood project has been implemented in Indonesia

Detailed core description with sedimentary structure analysis, paleocurrent analysis in FMI data and various property maps were conducted to identify the relationship between injection and production well. It also gives the information about movement of injected water. The sediment transport suggests some directional anisotropy in permeability. The distribution of geological heterogeneities and their influence on fluid flow characteristics were determined by generating maps and cross sections based on integration of log, core & petrographic data and qualitative information from production data. Parameters mapped included the distribution of porosity, log derived geometric mean permeability, clay content, and Dykstra-Parsons coefficients of permeability variations.

The results of this study showed a good correlation of facies distribution and sedimentation direction with flow of water movement behavior. The direction indicated relatively west to east sediment transport being perpendicular to the structure. It was also matched with tracer survey analysis and simulation model. In our success story, we applied the staggered line of full scale waterflood pattern to maximize the areal sweep efficiency and improve 5-7% recovery factor of total OOIP. This information also strongly supports the building of reliable static and dynamic model.

We proved that an integrated geological approach, including a good understanding of facies and sedimentation characteristics of reservoir will lead us to build successful waterflood and EOR project in the future.
A New Generation of Independent Temperature and Pressure Drilling Fluids System with Flat Rheological Properties, Low Invasion, Higher Shale Stability and Lubricity to Replace Oil Based Mud
Authors: Taraghikhah Shervin , Mohammadi Mojtaba Kalhor , Nowtarki Koroush Tahmasbi
Published: October 2019

The knowledge about rheological models is critical for a drilling fluid study. Typical drilling fluids have lower rheological properties in higher temperature or increase in gel properties which is the main reason for frictional losses when circulating. Keeping the rheological properties with constant value is one of the challenges to manage ECD and its effects. Our main goal is to introduce a flat rheology water based mud in order to improve fluid stability and prevent loss circulations and robustness while drilling operation.

The newly developed flat rheology water based drilling fluid system is formulated in different mud weights 1.12 S. G – 2.15 S. G to keep the shale inhibition, temperature stability and rheological properties in the highest possible performance.

This fluid system was subjected to hot rolling for 8 hours at 250 °F and 300 °F. Rheological properties were measured before and after hot rolling in several temperatures in order to confirm the flat and stable rheology. As well, other properties like shale recovery, fluid loss and lubricity were measured. After hot rolling (250 °F and 300 °F) rheology measurements were performed with Fann Viscometer for each mud in different temperature and pressures (60 °F to 180 °F) and the results were collected to be compared with before hot rolling data in the same conditions. All rheological data (PV, YP, Gels and etc.) remained the same comparing the properties before hot rolling.

This water based mud possesses the highest shale inhibition (shale recovery ranges from 95-100%). The API-fluid loss and HPHT-Fluid Loss were sufficiently controlled. Lubricity effect provided us with a really acceptable Kf (coefficient friction factor), under 0.2, which enables applying the system in high deviated zones or directional drilling. Stability tests show that this system has no incompatibility with high salinities and is adequately resistant in presence of contaminations. Also this system is applicable in the presence of weighting agents. Finally cost comparisons and environmental evaluations introduce this system as a cost benefit and environmental friendly system.

The most striking feature of this research is to design and introduce a flat rheology water based drilling fluid replacing conventional drilling fluid systems with temperature and pressure independent rheology along with other qualified characteristics. Significantly, this system is sufficiently environmental friendly and cost effective.
Non-Intrusive Technologies for Prudent Brown Field Redevelopment – An Operator's Experience
Authors: Yeap Wei Jian , Sidek Sulaiman , Naharindra Adhi , Riyanto Latief , Idris Khairul Nizam , Bakon Freddy Layang , Ambrose Jonathan Luke , Mackie Alexander , Rajan Santa , Sridhar Siddesh , Wong Kion Ming , Alias Azrul
Published: October 2019

In the oil and gas industry, operators strive to minimize loss time and production while keeping its facilities and operations safe. Over the past few decades, technological innovation has equipped the industry with the equipment and practices necessary to make the exploration and production more efficient, safe and environmental friendly. This paper discusses successful implementation of several non-intrusive technologies by the operator for redevelopment of maturing oilfield in offshore East Malaysia.

The field was discovered in 1967 and oil has been produced since 1972 from the major hydrocarbon accumulation in 8 producing reservoirs, sandwiched between shallow gas-bearing reservoirs and deeper gas/condensate-bearing reservoirs. Enhanced Oil Recovery (EOR) redevelopment project in the field began in 2018, targeting the major oil reservoirs and Non-Associated Gas (NAG) reservoirs. Crestal gas injection and flank water injection will be implemented to further develop the oil rims of A and B reservoir while Immiscible Water-Alternate-Gas (IWAG) injection will be implemented in the C reservoir. The EOR scheme will include infill drilling of new wells and workover of existing wells to deliver targeted incremental oil recovery.

The journey towards EOR redevelopment project consistently requires integrated contributions from multiple disciplines such as Petroleum Engineering, Production, Well Services, Facilities and Process Engineering, which has been facilitated effectively through Reservoir, Well and Facility Management (RWFM). This holistic work process involves creating critical strategy for EOR redevelopment activities, optimization decisions and asset management, ensuring the delivery of remaining reserves and long-term production maximization. By implementing RWFM collaboration and support, several non-intrusive technologies have been evaluated & implemented to solve long overdue problems such as online acoustic sand monitoring system, non-intrusive acoustic valve inspection device and active sonar meter.

Overall, this paper highlights the working principles, actual field results and lessons learnt from the application of non-intrusive technologies through RWFM collaboration that deliver significant cost and efficiency benefits as well as safety for prudent brown field EOR redevelopment.
Well Opportunity Register, Define and Selection: Changing the Game in Production Optimisation Using Automation and Analytics
Authors: Mario Cio Cio , Saputra Rini , Saefuddin Sera , Triyono Triyono , Metra Sabrina , Gaskari Razi , Martinez Henry , Songchitruksa Praput , Kartika Djaya Belly Agustinus , Sinha Rajeev Ranjan , Vadivel Karthick
Published: October 2019

The oil & gas industry is catching up to automation of traditional workflows practiced in the industry and implementation of artificial intelligence to fasten repetitive tasks. This is driven by the need to automate low-cognitive tasks enabling engineers to spend more time on high-cognitive components of the existing workflows, thus leading up to smarter decisions. This has been made possible by the recent developments and adoption of various analytics and machine learning tools.

Well intervention and workover are a routine and important exercise undertaken in the oil and gas industry where the objective is to identify the sick wells and diagnose the right intervention and workover to improve the production. A typical well intervention and workover candidates study includes: Identifying the underperforming wells,Diagnosing these wells and identifying the right workover/ intervention opportunitiesCreating a ranking of the opportunities using a standard approach.Forecasting the gain after workover/interventionRunning economic analysis to identify the candidate based on opportunity's profitability

Ujung Pangkah Oil and Gas Field is an offshore field located in Indonesia. The reservoir is a multi-layered carbonate oil and gas reservoir, being produced mostly through horizontal wells. An intelligent solution termed as SWORDS was developed for the Ujung Pangkah field that enables the engineers to be permanently aware of the intervention and workover opportunities. The SWORDS solution is driven by 'Automation & Analytics', where the ranking of the opportunities has been driven by a multi-criteria decision making process leveraging the Petroleum Engineering techniques practiced over decades.
Developing FDP Capabilities with PetroCup Petroleum Asset Simulator
Authors: Aslanyan Arthur
Published: October 2019

The paper shares practical cases on PetroCup – a new generation of on-line petroleum asset training and testing facility which helps developing the practical asset management skills and improve practical skill in associated disciplines, such as geology, petrophysics, flow simulations, production technology, well testing, production logging, surface facilities and petroleum economics.

Going through web-tournament is like a quest and represents a challenge for multi-disciplinary asset team during one or few days. The after-tournament debriefing helps asset teams understand their mistakes and learn from them.

Paper explains the specifics of public and corporate sessions and brings few case studies on both.

The training facility is based on PolyPlan simulator which has a very simplistic user-friendly webinterface which allows petroleum engineers perform typical routine activities (drilling, complex workers, varying pump and choke settings, well testing, logging etc.) with an intuitive button-click.

The PolyPlan simulator is modelling surface infrastructure, geological model, dynamic flow model, wellbore flow model, flow metering system for production gathering and water supply systems, popular OH and CH sensors and associated data acquisition procedures and reproducing a very realistic response to the typical field activities.

The paper also provides an overview of synthetic assets library and their complications and future plans on creating the new petroleum assets. The PetroCup facility provides a fast and cheap way of accumulating practical experience in petroleum asset management. It gives opportunity for people to learn new methods and tricks from sessions moderators and from each other.

Participants get opportunity not only to apply their engineering knowledge but also develop the presentation skill while convincing the team in their findings and ideas.

It also makes a great team building and helps people get closer and know each other while working on a project. The same facility can be used as automated unbiased assessment of accumulated experience in field development and associated petroleum disciplines.

The PetroCup allows people to join from different locations which substantially extends scalability of the knowledge sharing.
A Breakthrough Effort in Bringing the Learning Experience Closer to Employee by Using Online Blended Learning
Authors: Hidayatullah Aulia Syarifah , Larasati Ditta
Published: October 2019

Traditionally, people ought to come to a face-to-face or in-class training, whether arranged by company through in-house training or set up by a public provider. This conservative mechanism has its drawbacks for employees as in-class training require them to be in one location at a certain time. It becomes a challenge specifically for an employee in Oil & Gas company with its various working hour and working schedule (rotational or residential). This paper describes the breakthrough effort in PT Pertamina Hulu Mahakam (PHM) where training is delivered using online blended learning methods in which employees can participate actively in a learning program conducted from any region of the world without leaving the workstation or residence. Online blended learning does not require any fancy equipment or tools, as a participant only needs a laptop or desktop with speakerphone and of course, good internet connection. Besides, online blended learning may also worth to consider in terms of cost that might be lesser than conducting in-class training or sending people to conventional public training.
Localization of the Remaining Reserves of R Oilfield With Pulse Code Pressure Testing
Authors: Aslanyan Artur , Ganiev Bulat , Lutfullin Azat , Sagidullin Lenar , Karimov Ildar , Mukhliev Ilnur , Farakhova Rushana , Gainutdinova Landysh , Zinurov Linar
Published: October 2019

The paper is sharing experience on using the cross-well pressure pulse-code testing (PCT) to locate the remaining reserves for the waterflood infill drilling.

R Field is a very mature giant field in Volgo-Ural region of Russia and has been under production for more than 70 years.

One of the key challenges at this stage is to locate the remaining reserves which have been migrating over the field following the waterflood patterns with a lot of areal and vertical flow profile complications.
Successful Application of Novel Modified HF Acid System for Sandstone Matrix Acidizing in B Field
Authors: Ting Chang Siong , Kamarudzaman Zayful , Aris M Ikhwan , Hasbi Nurul Ezween , M Jeffry Suzanna Juyanty , M Shafian Siti Rohaida , Chandrakant Ashvin , Hassan M Hafiidz , Kamaruddin Izam Ikhwan , Mohamad Khairul Idzwan
Published: October 2019

Fines migration is the common formation damage mechanism in the sandstone reservoir of field B which has less established information on mineralogy distribution. There were many attempts to remediate the formation damage using conventional mud acid fluid system but resulted in mixed success rates. This situation warrant for the need for a modified acid recipe to avoid aggravation of fines migration problems in this field post acid treatment.

This paper presents the pilot application of a modified HF acid recipe incorporating chelate. The paper also depict the evaluation process that includes candidate selection, laboratory workflow and results, treatment design, execution strategy and the post job analysis on well B-1S. In order to increase the acid stimulation success rate, the team analyzed numerous post job reports of the nearby wells that were previously treated with conventional mud acid system. The root causes of the previous job failures were identified, such as prolonged soaking of acid in the formation due to unplanned platform shutdown and limited platform deck space. Taking these factors into account, the modified HF acid system (with 1.0% HF) was selected for execution in B Field. The pilot execution resulted in double the production compared to the pre-treatment rate. The modified HF acid system has also improved the economics of the project due to its lower cost since it is a one-step system and has lower additives requirement.
Case Study Channel Fracturing for High Production Improvement in a Tight Conglomeratic Sandstone Reservoir
Authors: Kartiyasa Fauzan Agung , Sitaresmi Ratnayu , Wahyuni MG Sri , Oetomo Hari Karyadi , Suandana I. Wayan
Published: October 2019

Channel fracturing becomes more popular as novel method of hydraulic fracturing, with increasingly successful in its implementation. This new method of fracturing, is pulsing proppant into formation instead of just continous pumping as in conventional fracturing. The proppant is mixed with fibrous material, which enables formation to sustain the closing pressure, even with the conductive channel within the fracture; it functions as the pillars of the fracture. The stimulated well is penetrated and producing from poorly sorting conglomeratic reservoir with secondary porosity and muddy micro-porosity; hinderes hydrocarbon flow to reservoir. A well was selected as a pilot well candidate, after reviewing the well test, it reached 230 BOPD. The permeability of the well is 1.78 mD with reservoir pressure of 1188 Psi. Recently, the well produces intermittently 9 to 20 BOPD, assisted by sucker rod pump artificial lift. Initial step is to evaluate the well by using Candidate Selective Factor (CSF), which is based on rock mechanics parameters and stresses within the formation. Afterward, initial design is constructed based on well parameter and its surrounding wells. After the pre-fracturing treatment, which consists of breakdown test, step rate test, and minifrac test, the fracuring operation is re-designed. The re-design includes the special pulsing pumping technique, and then followed by the mainfrac operation. In the actual operation, the proppant was pulsing into formation for eleven times. After channel fracturing, the productivity index of the well increased significantly by 10.3 times with an oil rate of 155 BOPD. Channel Fracturing; a novel technology of hydraulic fracturing; is not only increasingly succesful in its application for giving well production increase, but it also it uses materials that will give less probable of screen out. This method will be implemented in the whole field.
Case Study: Trouble Shooting of Gas Turbine Generator GTG Trips Due to Gas Turbine High Exhaust Temperature Spread While Operating on Liquid Fuel
Authors: Anwar Zeeshan , Manikandan Arumugampillai
Published: October 2019

Gas Turbine Generator (GTG) availability is one of the most critical requirements for any plant production in oil & gas industries. The subject case study provides the information and root cause analysis done on the number of trips happened on a dual fuel Gas Turbine due to high exhaust temperature spread while operating on liquid fuel, that affected plant power production requirements.

An exhaust temperature spread refers to a high differential in temperature readings between the thermocouples placed radially around the exhaust of a gas turbine. Spread indicates the difference between maximum and minimum temperatures recorded by exhaust temperature thermocouples. If spread is allowed without correction, it will result in reduction of residual life of downstream components of the Gas Turbine. The worst exhaust temperature spreads occur when the hottest and coldest spot are nearer i.e. exhaust thermocouple readings are grouped very closely adjacent. Most exhaust temperature spreads are the result of combustion section problems that can lead to premature failure of turbine blade /bucket.

Site is configured gas turbine running on dual fuel that is fuel gas and liquid fuel driving generator for power generation. During the commissioning and unit start-up the exhaust spread was normal on both fuel gas and liquid fuel. After running the unit for almost a year there was a trip event. Evaluation of the trip data indicated that the exhaust temperature spread is very high when the unit was running on Liquid fuel.

It was agreed to start the unit again and perform the fuel transfer from gas fuel to liquid fuel at lower load of 5 MW, the unit tripped again when it was switched to liquid fuel due to same issue of high exhaust spread.

Further checks were performed, and it was established that the high exhaust spread is due to hardware issue, related to the fuel nozzles and liquid fuel or purge air system check valves

There are number of factors that caused the high spread exhaust issue, all of them are verified by engineering in details and recommendations are provided for the future operation of the machine without the subject issue of high exhaust spread. Most probable causes identified was the Clogging of Fuel Nozzles and issues with the Liquid Fuel check valves and Atomizing Air Purge System Check Valves.

High exhaust temperature spread is one of the major concerns in liquid fired Gas Turbines leading to low reliability of Gas Turbine & more down time. In this case study some of the rare reasons for the high spread issues & troubleshooting are analyzed and presented in detail. The information contained in this case study is broadly applied in Oil and Gas plants where Gas Turbines are installed for power generation.
A Holistic Approach to Identify the Optimum Cost-Performance Surfactants for Chemical EOR Projects
Authors: Rommerskirchen Renke , Jakobs-Sauter Britta , Ng Rick , Nijssen Patrick
Published: October 2019

The surfactant selection for chemical floods usually starts with an extensive lab study identifying the formulation that provides the best recovery performance. However, it is oftentimes overlooked that in a laboratory setting the requirements on product availability and applicability are less sensitive than for a field scale injection. Thus, there are various other aspects that contribute to the overall economics of chemical selection which also need to be taken into account.

Aside from the molecular properties, the manufacturing aspects have to be examined carefully to allow proper planning and ensure the supply of large volumes for full field implementation on time. Furthermore, opportunities to simplify and optimize the logistics (i.e. packaging, regulatory compliances …) help to reduce the cost of a chemical injection project. This is also strongly connected with the handling properties of the selected materials when it comes to the blending of the final injection cocktail (e.g. activity, viscosity, storage conditions, etc…).

This paper describes the crucial factors that impact the economics of a selected surfactant for a chemical EOR project, taking into account the production, transportation, delivery form, application performance, handling, amongst others. Another point that will be discussed, is the option to create in-country value and reduce logistic challenges by performing a final production step regionally close to the project site.

In the end, we conclude that involving the suppliers at a very early stage of the screening process helps to eliminate unsuitable molecules. It also allows for proper planning and leads to the most appropriate procedure. By taking into account the whole economics picture, a win-win situation can be created and the project is beneficially optimized. Forward thinking the treatment of both injected and produced fluids can be part of this optimization process.
Fracturing Fluid and Geomechanics Integration Solves Hydraulic Fracturing in the HP/HT Triassic – Jurassic Petroleum System, Krishna Godavari Basin, India
Authors: Gondalia Ravi Ramniklal , Kumar Rajeev Ranjan , Zacharia Joseph , Shetty Varun , Bandyopadhyay Atanu , Narayan Shashank , Bordeori Krishna , Singh Mukund Murari , Shah Arpit , Choudhary Dinesh , Sharma Lovely , Ray Maria Fernandes , Sarkar Samarpita , Moulali Shaik , Das Santanu , Rao Dasari Papa
Published: October 2019

The Triassic–Jurassic petroleum system reserves in Krishna Godavari Basin are found at 3500 to 4500 m depth with bottomhole static temperature (BHST) ranging from 270 to 340°F. Hydraulic fracturing is required to produce economically from these wells because the in-situ permeability of these sands is in the range of ~ 0.01 md. Hence, after perforations, minimal production is observed or the flash production from these wells dies out in a short time span.

Between 2010 and 2017, several appraisal wells were drilled and completed using hydraulic fracturing in the onshore Krishna Godavari Basin. However, the success rate of effective fracture placement and sustained production enhancement due to hydraulic fracturing was limited. This was attributed to insufficient understanding of rock mechanical properties and lack of a refined fluid fracturing system despite using a superior fluid system like carboxymethyl hydroxypropyl guar (CMHPG) with organometallic zirconate-based crosslinkers.

In 2018, nine wells were successfully hydraulically fractured, and sustained production from these wells was established using a simple borate-based crosslinked fluid system. A key change for the field was rather than designing and pumping fracturing fluid based on only BHST, one of the critical components that led to better proppant placement is the stable fracturing fluid that was fine tuned for the well based on factors like change of source water, tubular shear exposure time for designed fracturing treatment pumping rate, and hydrocarbon properties. This combination of rock mechanical properties and fracturing fluids used is captured as the efficiency of the fluid system, and this governed the usage of fluid loss additives, again a novel introduction for the field. Finally, the key to producing these sands was adequate cleanup and minimal guar residue to maximize the proppant pack conductivity. The paper also discusses the strategy to design fluids with minimal guar loading to reduce polymer retention and to achieve maximum fracture fluid recovery. This robust management of fracturing fluids along with understanding of rock mechanical properties can be seen in the post-fracturing production results.
Philosophy of EOR
Authors: Babadagli Tayfun
Published: October 2019

This paper seeks answers, through a ‘philosophical’ approach, to the questions of whether enhanced oil recovery projects are purely driven by economic restrictions (i.e. oil prices) or if there are still technical issues to be considered, making companies refrain from enhanced oil recovery (EOR) applications. Another way of approaching these questions is to ask why some EOR projects are successful and long-lasting regardless of substantial fluctuations in oil prices. To find solid answers to these two, by ‘philosophical’ reasoning, further questions were raised including: (1) has sufficient attention been given to the ‘cheapest’ EOR methods such as air and microbial injection, (2) why are we afraid of the most expensive miscible processes that yield high recoveries in the long run, or (3) why is the incubation period (research to field) of EOR projects so lengthy? After a detailed analysis using sustainable EOR example cases and identifying the myths and facts about EOR, both answers to these questions and supportive data were sought.

Premises were listed as outcomes to be considered in the decision making and development of EOR projects. Examples of said considerations include: (1) Every EOR process is case-specific and analogies are difficult to make, hence we still need serious efforts for project design and research for specific processes and technologies, (2) discontinuity in fundamental and case-specific research has been one of the essential reasons preventing the continuity of the projects rather than drops in oil prices, and (3) any EOR project can be made economical, if technical success is proven, through proper optimization methods and continuous project monitoring whilst considering the minimal profit that the company can tolerate.

Finally, through the ‘philosophical’ reasoning approach and using worldwide successful EOR cases, the following three parameters were found to be the most important factors in running successful EOR applications, regardless of oil prices and risky investment costs, to extend the life span of the reservoir and warrant both short and long-term profit: (1) Proper technical design and implementation of the selected EOR method through continuous monitoring and re-engineering the project (how to apply more than what to apply), (2) good reservoir characterization and geological descriptions and their effect on the mechanics of the EOR process, and (3) paying attention to experience and expertise (human factor).

It is believed that the systematic analysis and philosophical approach followed in this paper and the outcome will provide proper guidance to EOR projects for upcoming decades.
Case Study of Underground Gas Storage in a Lean Gas Condensate Reservoir with Strong Water-Drive
Authors: Tien Chihming , Lin Hsiaowei , Chen Jinfa , Wu Weijr
Published: October 2019

The largest gas discovery in Taiwan is the Tiehchenshan (TCS) gas field, which is a lean gas condensate reservoir with strong underlying aquifer. The gas reservoir has been produced since 1965, and in 1990, in light of considerations regarding domestic gas demand and available infrastructure, it was converted to underground gas storage (UGS) by injecting re-gasified LNG.

It was recently found that one of the blocks serving for gas storage is facing gradual water encroachment. In addition, between 2011 and 2012 it was discovered that average reservoir pressure suddenly increased by about 170 psi. It was surmised that this could be a result of the influence of strong water-drive due to the imbalance of injection and production over a very long period.

The aims of this study are to effectively assess the extent of gas bubble in the reservoir through the integration of a geological model, reservoir simulation, and history matching process associated with a 54-year production history; and, on this basis, to re-evaluate working and cushion gas requirements for feasible operating conditions. However, owing to the poor quality of oil production data, the black oil model is utilized for reservoir simulation rather than the compositional model. Tracer tracking of reservoir simulation is also applied to identify the movement of injected gas due to the limitations imposed by the lack of the composition model.

The reservoir simulation model for describing the dynamic behavior of the UGS was successfully developed and verified, and it was also applied to evaluate the possibility of the UGS expansibility. Results of the study suggested that one of the gas storage blocks in the UGS is no longer appropriate for its function. Instead of using it for storage, it is recommended that the gas from it be produced as quickly as possible accompanied by water encroachment.