bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimal Zonation of Geological Formations and Identification of Pore Structures for Sandstone Reservoirs, Including Variation in Cementation and Fining Sequences
Authors: Behrenbruch Peter , Hoang Tuan G. , Huu Minh Triet , Bui Khang D. 
Published: October 2017

Abstract
Hydraulic Flow Zone Unit (HFZU) analysis for characterising cored formations using the Carman-Kozeny (C-K) equation was first proposed in the late 1980s. More recently this formulation was amended as for diverse formations, the C-K equation typically works in less than 50 percent of the cases. The modified formulation includes a cementation factor to handle C-K non-compliant cases. The objective of this paper is to build on these formulations, covering the full range of geological situations.
The study presented compares traditional reservoir characterisation approaches with the latest geological zonation techniques, showing how the full range of relationships may be universally accommodated. Such zonation is the best preparation for optimal reservoir simulation. In particular, it is shown how variable grain size and sorting may be visualised. Results are presented in traditional space, logarithmic permeability vs. porosity, and in model space: hydraulic radius, or reservoir quality index vs. porosity group, porosity fraction divided by the solid fraction.
It is shown that the methodology presented can deal with any sandstone (clastics) situation: C-Kcompliant and non-compliant, further categorising variable cementation and other diagenetic features, and including interbedded intervals and fining sequences. The zonation of a geological interval using the methods presented is the best basis for choosing vertical gridding for a dynamic reservoir simulation model, circumventing traditional upscaling, often fraught with inconsistencies. It has been found that the Flow Zone Indicator, a measure of grain size (or pore throat size) is the best parameter for zonation, followed by sorting of grains or pore throats. A Global Characteristics Envelope, encompassing 6 dimensions, is used to further validate final results.
The paper presents several case histories, covering fluvial and marine environments and a range of geological depositions and facie, including pore-fill (typically kaolinite). Fields are located offshore Australia and overseas.
Evaluation of the Kinetics of Asphaltene Flocculation during Natural Depletion and CO2 Injection in Heptane-Toluene Mixtures
Authors: Kord Shahin , Dashti Hossein , Zanganeh Peyman , Ayatollahi Shahab 
Published: October 2017

Abstract
Carbon dioxide miscible flooding is known as a very efficient and challenging enhanced oil recovery (EOR) method. Besides the high oil recovery efficiency, the asphaltene precipitation and deposition is believed to be triggered by a perturbation of the thermodynamic equilibrium present in the reservoir. Asphaltene deposition results in wettability alteration and plugging in the reservoir as well as affecting the production facilities. The complicated mechanism of phase separation in asphaltene-containing systems makes it crucial to study the effects of different parameters on the aggregation of asphaltene particles.
In this study, a novel high-pressure visual cell equipped with a high-resolution microscope along with the image processing software was prepared to investigate the growth of asphaltene particles on a sample reservoir rock. The quantity of asphaltene deposition was determined at several pressure depletion steps and different temperatures with and without CO2 injection. This would help to evaluate the kinetics of asphaltene flocculation resulting from CO2 injection or pressure drop due to natural depletion. The results reveal that the amount of asphaltene deposition increases with increasing the concentration of the injected CO2. The results of this study demonstrated that the molecular structure of asphaltene could have a noticeable effect on the asphaltene deposition.
Optimization Method for Casing Design Based on Coordination Mechanism of Drilling Risk and Cost
Authors: Sheng Ya-Nan , Guan Zhi-Chuan , Wei Kai , Zhao Ting-Feng 
Published: October 2017

Abstract
Because of the complex geological structure and unpredictable geologic environment, drilling engineering is characterized by high risk and high cost, especially the drilling processes of complex formation or deep water condition. Controlling drilling cost and ensuring the drilling safe has been the focus of research at home and abroad. So this article's objective is to establish the casing program optimization method based on risk and cost coordination. In this article, based on the drilling quantitative risk assessment and the drilling accidents report, the risk probability profile can be obtained. Then according to the theory of fuzzy mathematics, the model of risk degree judgment was established. The drilling risk probability profile is divided into three parts: the safe region, the transitional region and the dangerous region. No special treatment is necessary for the safe region. Risk in the dangerous region must be avoided before drilling. The risk in the transitional region must take account of both risks and costs. The risk treatment and aversion cost calculation model were established. Then the coordination of drilling risk and cost was proposed. Finally, the optimized casing program based on this method was obtained. After the summarization of this principle, taking the drilling data of one block of a basin in west China as the example, the risk level identification results were mainly identical with the realities, and indicated that the method could satisfy the needs of drilling engineering. Case study showed that the decision making for casing design of one pre-drill well was optimized based on the coordination mechanism. The well was successfully completed without risks and the drilling cost decreased by 15%.
Enhanced Reservoir Characterisation Using Integrated Production Data Analysis
Authors: Motaei E. , Ataei A. , Yazdi E. , Khor Y. Y. , Faiz M. 
Published: October 2017

Abstract
Production data analysis (PA) refers to all analytical approaches and tools to reveal reservoir properties, performance, and characteristics such as material balance, Flowing Material Balance (FMB), Pressure Transient Analysis (PTA), Rate Transient Analysis (RTA), Decline Curve Analysis (DCA) and deconvolution.
PA provides robust information comprising reservoir container volume, depletion mechanism, reservoir connectivity and well performance. It provides the best view on reservoir performance and helps to characterize the reservoir to understand reservoir quality, boundaries and flow characteristics to develop and optimize current reservoir management prior to any dynamic modelling.
In this paper, the focus will be on analytical methods such as Rate Transient Analysis (RTA), Flowing Material Balance (FMB), Pressure Transient Analysis (PTA) and analytical simulation as an integrated approach for enhanced production data analysis in Gas fields. The idea of FMB has been introduced by L. Mattar (1997) and it is generally applied to determine oil or gas in-place using flowing pressure data (L. Mattar and Anderson, 2005).
The main objective is to show the methodology for production data analysis, illustrate its added value to reservoir performance monitoring as well as its advantages for well-test design and production forecasting.
The results show that different approaches need to be used consistently to enhance the reservoir characterization and improve reservoir understanding in using production data prior to full field dynamic application. Integration helps to resolve uncertainties quickly and economically.
Drilling Optimisation of Extended Reach Multilateral Wells to Maximise Reservoir Contact in Carbonate
Authors: Verma Chandresh , Rodriguez Fernando , Qasin Qazi Mohammed , Chaaouri Aramco Mohsen , Akel Sami , Akiki Ghassan , Afolabi Jonathan 
Published: October 2017

Abstract
Energy consumption and demand are steadily increasing. Hydrocarbons have been an important energy provider for several decades, but production from mature oil and gas producers is declining. Great effort is put into improving oil and gas reservoir recovery to meet this rise in energy demand.
In the subject reservoir where the pay zone is a thick, multi-layered limestone, characterized by low-permeability; conventional techniques yield lower than expected production results.
To improve production and the ultimate recovery of the field, extended-reach drilling (ERD) wells with long horizontal multilaterals (Quad and Penta-laterals well types) were drilled to attain maximum reservoir contact (MRC), ranging from 10 to 14 Km. These wells equipped with intelligent completions, enable uniform contribution along the extended horizontal intervals. This contribution is achieved through better flow management of the different sections of reservoir contact, reducing operational drawdown pressures, and delaying gas and water breakthrough. The result is high well potentials, improved long-term performance of sweep and recovery, and increasing net worth of the drilling investment.
This paper presents the lessons learned from hundreds of ERD multilateral wells drilled in the field, including integrated operations, progressive approaches and innovative applications, improved drilling practices on a continuous basis, and the tools and techniques used to drill and complete the wells safely and efficiently.
These efforts achieved a milestone record rate of penetration (ROP) in the Middle East of 5,000 feet per day, and as a direct result contributed to minimizing well delivery time by 35 % and average 25% reduction in well cost in an always challenging drilling environment.
The design approach, job execution and evaluation of drilling performance are presented in this paper; as well as key technical challenges and risks encountered during planning and execution stages and how these were mitigated and overcome for MRC improvement and optimization.
Well construction was challenged to meet the complex multi-lateral with long cantilever sections.
The MRC optimization schemes applied in the field resulted in dramatically reduced days of drilling operations that led to millions of dollars in project savings and the achievement of world class drilling records.
An Integrated Approach to Understand the Variable Fluid Contacts in a Giant Carbonate Field of Middle East - A Case Study
Authors: Nandwani S. , Kumar P. D. , Singhal M. , Gogoi J. M. 
Published: October 2017

Abstract
This case study attempts to explain a fully integrated approach, to develop a comprehensive understanding of variable fluid contacts in a giant carbonate field (with stacked reservoirs) of Middle Eastern region. With very little to no water handling facility at surface, this study helps the operating unit to sustain dry hydrocarbon production by identification of potential water producing zones. The outcome of this study also has a direct impact to optimize future well locations/numbers, and to come up with a perforation strategy integrating surface and subsurface disciplines.
A detailed fluid fill analysis is done with the available data. Oil, water, and transition zones are picked in individual wells (~50) and correlated with Drill Stem Test (DST) data, mud log data, special log data (viz. NMR), and electro-facies data (rock typing from logs) to arrive at an understanding about lateral and vertical fluid distribution in the field. Reservoir surveillance data, in few wells, is also used to calibrate the fluid distribution model.
Fluid-fill distribution mapping has shown that fluid fill varies both vertically (between zones) and laterally. Vertical variation can be attributed to capillarity of different rock types – rocks with good porosity and permeability having the deepest oil fills with little to no transition zones, while low porosity rocks have long transition zones and shallow oil fills. A consistent inverse relationship is observed between the porosity and thickness of the transition zone for all reservoirs. Also, lateral variation in the fluid fill is observed in ENE-SSW direction where aquifer is present. Open hole log interpretation shows residual oil signature in wells in W-NW direction which is further confirmed by available mudlog data. A structural-tilting theory helps us to explain these lateral variations across the field. Observations infer that a tilting episode has sunk the NW part of the structure, post oil migration. Consequently, the oil-filled rock that submerged below Free Water Level (FWL) underwent imbibition. The evidence of imbibition is now seen in the form of a residual oil signature. Understanding and mapping of the residual oil zones is critical to sustain the production of dry oil and delay/minimize the water production in the field.
The novelty of this study is to reiterate cross discipline integration, where different pieces of data when put together helps to solve the most complex of the problems (viz. variable fluid contact in carbonate reservoirs, rock typing scheme), thereby having a direct impact on the field development plan and consequently on the ultimate hydrocarbon recovery.
Production Allocation Challenge with Presence of Apparent Down Flow ADF Phenomenon: A Case Study in Malaysia Wells
Authors: Rosli M. Aliff , M. Nordin Norintan Farina , Abdul Latif Azzad Hafiz , Hashim Haziq , Nurzahira M. Shuib Siti , Farid M. , Amin M. , Hamid Afiq A. , Ramli Anis Salwa 
Published: October 2017

Abstract
Production allocation is required in hydrocarbon accounting to determine the hydrocarbon volume at the point of sale and for back allocation to the field, platform, well, and down to the individual reservoir levels. Production allocation is not only important for the purpose of reporting to the host government but also to understand the remaining hydrocarbon reserves which are crucial for reservoir management and input to the full field review studies.
For wells producing from commingle zones, the individual zonal contribution determination is important. The Production Logging Tool (PLT) is commonly used to measure each reservoir's contribution downhole. Latest technology advancement in directional drilling over time has allowed for more deviated and horizontal wells. Well deviation is one of the factors affecting fluid flow pattern in a borehole apart from the phase holdups and fluid properties (PVT). As production fluid flows upwards in a deviated well, the movement of the lighter phase to the high side of the well displaces the dominant heavier phase liquid, causing it to flow downwards. This borehole phenomenon is commonly known as Apparent Down Flow (ADF).
A standard PLT has a centralized spinner configuration and when run in wells experiencing ADF will likely cause the spinner to measure an incorrect fluid velocity. Depending on the degree of the holdup of the heavier phase, the spinner may show a reduced or even negative rotation if it is immersed in the heavier phase fluid. Conversely, the spinner may show faster rotation if it is located in the lighter phase fluid. The advanced PLT, with its array of mini spinners and holdup sensors, was developed in part, to measure the effects of ADF and was designed to cover the well's cross section area, giving a more accurate description of the flow behavior; thus better measurement and understanding of ADF phenomena.
It has been observed from many production logging surveys that were conducted using a standard PLT, where the spinner shows negative readings during the flowing condition, indicating fluid re-circulation (or fluid fallback). However, information from other sensors such as fluid density identifier and temperature tool does not support these findings (of fluid re-circulation), which results in inaccurate rate calculation to determine zonal contribution. To overcome this challenge, the advanced PLT can be used to measure the contribution for each zone more accurately as the effects of ADF can be further understood. The calculated production rates from the advanced PLT were found to be more representative despite the presence of ADF in the wells.
This paper discusses some case studies on the application of the advanced PLT in overcoming the challenges of quantifying zonal contribution in wells experiencing ADF.
Development of a Remotely Activated Liner Hanger System While Minimizing Operational Risks
Authors: Munshi A. A. , O'Connor K. , McMahon S. , Carmody M. 
Published: October 2017

Abstract
Operators for deepwater and extended-reach wells, where daily rig costs can exceed $500k per day, are continuously exploring methods to reduce nonproductive time (NPT) and increase operational efficiency. One particular area of interest is the deployment of liner strings, which are commonly used as an alternative to long casing strings to minimize well construction costs and increase drilling efficiency. For deepwater and highly deviated applications, hydraulic liner hangers are predominantly used over mechanical tools due to the limitations of pipe manipulation needed to set the hanger. The traditional method for setting a hydraulic liner hanger includes the use of one or more activation balls dropped from surface so that pressure can be applied to the workstring to function the hydraulic liner hanger and running tool. However, in deepwater and extended-reach applications, the time to pump or gravitate the ball on seat can take up to 3 hours. In addition, there are many cases where the ball never properly lands on seat, which can lead to days of more NPT. Developing a liner hanger system that does not rely on dropping activation balls from surface, nor rely on pipe manipulation can reduce the time required to run the liner hanger and minimize issues that lead to increased NPT.
This paper presents how a new liner hanger system was developed to use simple mud flow signals to remotely communicate with a downhole controller located on the workstring. The downhole controller receives the specific activation signal from surface and then relays that signal to the liner hanger or running tool via an acoustic signal. The liner hanger and running tool are then actuated with an electronically triggered hydrostatic actuator.
This new system does not require dropping activation balls from surface, simplifying system hook-up and reducing the amount of time required to set the liner hanger. The system also allows a solid liner hanger body with no pressure ports, eliminating the potential leak paths inherent to hydraulic liner hangers.
The novel approach to design and develop the remote liner hanger system to minimize operational risks and reduce development time will be discussed in detail. This includes the evolution of the remote system from field-proven hydraulic liner hanger technology and the results from testing performed to qualify the remote communication methodology. This liner hanger system improves well construction efficiencies and is a step in the direction of a smarter and safer oilfield through more automated operations.
Perforation Portfolio Management in Tunu Mature Giant Gas Field by Implementation of Intensive Well Review and Its Application in Production Forecast Improvement and Optimization of Well Intervention Planning
Authors: Purwanto Eko Yudhi , Herawati Suhesti , Rau Irfan Taufik , Anggoro Jodi , Suwito Edy 
Published: October 2017

Abstract
Tunu is a mature giant gas field, located in swamp area of Mahakam delta. It covers an area of 75 km long and 15 km wide with enormous multi-layer sand-shale series deposited within a deltaic environment. The production commenced in 1990 and peaked in 1999 (1.5 Bcfd yearly average), with current production around 600 MMscfd, and nearly 1,200 wells drilled from 34 platforms.
As the field is entering into the late stage of its life and number of new wells being drilled is decreasing, the field potential is now quite dependent on the existing perforation portfolio. Owing to the significant number of wells, with multi-layer reservoirs encountered by each well, the perforation portfolio needs to be managed in an efficient and detailed manner.
An intensive well review has been performed, involving more than 9,000 reservoirs located in over 800 active wells. It commenced with an evaluation of perforation gain and its associated risks at reservoir level, which are then progressively summarized into higher levels; well, platform, and field. Perforation sequences are then defined for each well following a bottom-up perforation strategy while also adapting the risks of each reservoir. Ultimately, an organized reservoir chart is constructed where we can dynamically surveil the field perforation portfolio.
Results of this intensive well review have enabled the shift of production forecast methodology from statistical toward deterministic approach. In the new approach, for instance, perforation sequences and time interval between the sequences in each well are deterministically determined on a well by well basis according to the aforementioned reservoir chart. Compared to the previous methodology, this new approach yields a better representation of the actual operations.
Another area benefited by the results of the intensive well review is the optimization of well intervention planning. The identified workload is grouped together based on the remaining perforation portfolio of each platform while also respecting their location to define several well intervention clusters. Implementation of this clustering system optimizes perforation planning which reduces the time spent by perforation barges to travel from one platform to another, thus allowing more time for perforation.
Drilling and Completion Fluids Customization to Achieve Maximum Well Productivity in Lower Burgan Reservoir, Case Study from Kuwait Field
Authors: Al-Ajmi Abdullah , Al-Rushoud Abdulaziz , Gohain Ashis , Khatib Faiz I , Al-Gharib Majed , Al-Ajmi Ali , Al-Mekhlef Alanoud Mahdi , Mustafa Mohammed Abdulla , Mago Ankit , Rossi Arnaldo , Rane Praful 
Published: October 2017

Abstract
With the desired objective of increasing Oil production, the Operator initiated a high inclination well drilling campaign utilizing open hole completions with Inflow Control Device (ICD) screens in Burgan (sandstone) reservoirs. The approach dramatically reduces the effect of water and gas breakthrough, while optimizing production rates throughout the completion interval.
Challenges encountered while drilling these high inclination wells included increased non-productive time resulting from interbedded formations with varying formation pressures, wellbore instability in the reactive, stressed shale sections and hole cleaning challenges.
A non-aqueous reservoir drilling fluid (RDIF) system was customized with extensive laboratory testing to overcome the challenges and protect the reservoir from drilling fluid damage. The formation damage phenomena investigated included foreign particle invasion, formation clay swelling, chemical incompatibility, oil wetting of the reservoir rock, emulsion blocking and fluid invasion (water blocking).
Based on the reservoir rock morphology and the calculated pore throat size distribution, the bridging particles type, size distribution, and concentration to be selected to rapidly establish a tight thin filter cake and prevent the invasion of filtrate and fine drilled solids deep into the formation to minimize damage to reservoir and avoid getting differential stuck pipe incident.
Removal of skin damage resulting from external and internal filter cake deposition while drilling reservoir with invert emulsion fluid is vitally important to enhance production. The customized near-wellbore damage remediation system constructed around an in-situ acid precursor was designed to improve hydrocarbon recovery.
This paper also summarizes engineering best practices developed while drilling, tripping and performing PST to achieve the operators well objectives. The lessons learned during these applications were incorporated into future wells to standardize operating procedures and improve field performance.