bluuebunny/crossref_metadata_2025_split huggingface dataset:
Scenario-Based Pore Pressure Prediction to Reduce Drilling Risks, Examples From the Sarawak Asset, North West Borneo, Malaysia
Authors: D. Warrlich Georg Mathis , Palm Danielle , van Alebeek Hans Johannes , Volchkov Dmitry , Hong Sia Chew , Adams Erwin W , Ryba Artur , Schutjens Peter Maarten , Stevens David A , Peacock Anthony William , Row Zuka , Ghosh Kallole 
Published: May 2016

Abstract
Pore-pressure prediction in a mature hydrocarbon province with producing fields bears issues different from an exploration or immature basin setting. Appraisal and production activities can introduce anadditional set of complications that needs to be considered to make well-constrained pore-pressurepredictions. Problems for infill drilling can arise from severe changes in rock strength (fracture gradientreduction), caused by depletion of reservoirs through production, or development drilling in neighboringfields, if there is pressure communication via a common aquifer. Increases above initial pressure can be caused by crossflow from overpressured reservoir layers through poor cement bonds or abandonments. Reservoirs can also receive additional pressure through water or gas injection.
The Luconia gas province is a mature basin and several stages of successful exploration, appraisal, development and infill-drilling campaigns. Shell, supported by its partners, has successfully overcome the above mentioned issues by thorough and innovative pore-pressure prediction approaches. In addition to the standard bracketing of uncertainties, 3 key process elements are employed:proper framing of the pore-pressure prediction and continued interfaces with all stakeholders anda 'scenario-based'prediction approach, that captures all possible effects caused by appraisal and production of the target reservoir or neighboring fields, and that predicts their impact on the pore pressure of the reservoir to be drilled.Risks identified are captured and mitigated via a 5 point pore-pressure prediction that spans a facilities design range as well as a wider drilling range. The drilling-range end members have a low probability of occurring, but have to be captured to enable hardware selection that ensures safe drilling execution. State of the art technologies are employed to achieve this, including 4D seismic, regional databases, innovative modeling methodologies and full integration in a well-delivery process.
Characterization of Volcanic Reservoir - New Integrated Approach: A Case Study from Raageshwari Deep Gas Field, Rajasthan, India
Authors: Chowdhury Manabesh , Guha Rupdip , Singh Surender , Verma Sumil Kumar , Tandon Rohit , Gould Thomas , Taylor Andrew , Goodall Ian 
Published: May 2016

Abstract
The Raageshwari Deep Gas Field is located in the Central Basin High, in the southern part of the Barmer Basin, Rajasthan, India. The major reservoirs are eruptive volcanics and subsequently deposited clastics of Cretaceous - Early Tertiary age. The reservoirs are micro porosity-low permeability gas condensate systems. Exploration wells were conventionally tested with gas production rates of 2–4 MMScf/day at high drawdowns. In the development phase, deviated wells with multi-stage hydraulic fracturing have shown multi-fold improvement in production performance.
Volcanic reservoirs are characterized by quick changes of lithofacies both laterally and vertically resulting in strong vertical and horizontal heterogeneity. Unpredictable distributions of pore and fracture networks resulted in variable well performance and productivities. Difficulties in reservoir characterization pose an immense challenge to effective well and reservoir management.
Comprehensive reservoir characterization studies were undertaken to unravel the complexity of the volcanic reservoirs and to capture the uncertainties. The workflow integrates data from volcanic outcrop analogues, conventional core (visual description, thin section petrography, geochemistry, RCA, Dean Stark and SCAL), mudlogs (gas shows and chromatography), and wireline logs including dipole sonic, image and NMR logs. Productive reservoir units deliverability was validated with production logs, whereas the effectiveness of hydraulic fracturing was matched with micro-seismic data coupled with seismic attributes (AntTrack volume). Matrix permeability coupled with fracture characterization was used to match well performance. Spatial distributions of reservoir properties were populated by geostatistical techniques incorporating available geometries and flow unit dimensions from analogues and well information.
The validity of this approach has been confirmed with most recent wells as blind tests and a successful production test from a deeper unit. The approach also emphasises the importance of integrating different datasets for detailed reservoir characterization leading to increased confidence in effective reservoir management of this complex reservoir.
Exception-Based Surveillance - Integrating Well Models, Real Time Production Estimates and Hydrocarbon Accounting Tool in Well Operating Envelopes to Ensure Optimal Well Production within Safe Limits
Authors: Sahu Sambit , Singh Ankur , Al Balushi Mahmood , Konwar Anupam , Bahukhandi Naveen , Briers Jan 
Published: May 2016

Abstract
On a daily basis, the Well, Reservoir and Facility Management (WRFM) team screens all producer and injector wells to identify those wells that are under-performing or outside safe operating limits. A 'Well Operating Envelope' tool has been developed, focused on establishing the boundary conditions of various safety-critical parameters and optimized well performance. Current well operating conditions, derived from real-time gauges and flow estimates from Production Universe (PU), are monitored vis-à-vis these parameters via this tool to identify the "problematic" wells.
Various diagnostic tools (i.e. Surface P-Q curves, VLP-IPR Nodal Analysis, Tulsa Flowline erosion model, Gas-Lift response curve, Inflow performance, SC-SSSV pressure plot and Hall plot derivatives) have been used and visualized for better understanding of the well flowing conditions for both production and injection systems. This tool fetches data from multiple databases like Data Historian, Energy Components and Production Universe (PU); it is also capable of interfacing with Prosper and WinGlue to fetch well performance data automatically.
Following improvements have been observed with implementation of this tool:Traffic light and graphical representation enables quick well surveillance in identifying problematic wells and taking corrective measures.Monitoring of the daily PU estimated production vis-à-vis well tests, allocated production volumes and the physical well models will increase hydrocarbon accounting efficiency.Monitoring real-time parameters like FTHP, FBHP, and flowrates allows the Petroleum Engineers and Operations to operate safely within defined boundaries.Monitoring of parameters like GOR, drawdown will enable adherence to reservoir management guidelines and reduce potential reserve losses.
Visualization of information from multiple data sources into this real-time tool provides an effective and efficient monitoring to ensure optimal well production within safe limits on a day-to-day basis for well, reservoir and facility management.
A Dynamic Discrete Fracture Model for Simulation of Tight Low-Permeability Reservoirs
Authors: Lei Zhengdong , Tian Changbing , Wang Fang , Wang Wenhuan , Peng Huanhuan , Wang Tingting , Li Qianshan , Yu Zhu 
Published: May 2016

Abstract
Tight Low-Permeability reservoirs are characterized by natural fractures and hydraulic fractures, fractures frequently generated in injectors during long-term waterflooding operations. These fractures may have a significant impact on process performance and ultimate recovery. It is a great challenge to model accurately fluid flow between multi-scale, dynamic fractures and tight matrix rock.
In this paper, we develop a dynamic discrete Fracture modeling approach (DDFM) to simulate complicated flow through multiple fractures and tight matrix rock. The discrete fracture modeling (DFM) approach is applied to describe realistic large-scale fractures individually and explicitly. This entails highly constrained unstructured gridding and construction of a transmissibility list of all neighboring cells. The micro-fracture system is modeled by permeability sensitive to the stress change to resolve dynamic opening and closing. A fracture growth model was developed that incorporates the effect of geo-mechanical impact by injection pressure and injection-production ratio, which can simulate the formation of fractures and update the unstructured grid in a timely manner. The new model allows us to better understand the multi-scale and multi-physics flow behavior caused by complex fracture system.
The simulation results show that reservoir dynamic fractures play an important role in both direction and speed of water displacement fronts through tight low-permeability reservoirs. The oil recovery rate can increase or decrease significantly depending on the fractures orientation and the rate of fracture growth. The proposed simulation method provides a useful tool for modeling the effect of fractures on waterflooding performance and can be used to optimize injection pressures and rates, water quality as well as well patterns for maximizing oil recovery.

1 Introduction
Tight Low-Permeability reservoirs have low permeability and tiny pores. The long-term waterflooding operation always leads to a pressure increase near the wellbore. Because of the increase in pressure, most injection wells will generate dynamic fractures. These fractures generate during waterflooding operations and expand gradually over time, which seriously influence the reservoir performance and sweep efficiency. So the fracture propagation needs to be analyzed. The fracture length in conventional models was constant, so how to describe and simulate the dynamic change of fractures poses a challenge to discrete fracture modeling.
Empowering Women in the Oil and Gas Industry
Authors: Hii Rebecca Pek Cheah , Kardani Ilen , Bt. A. Jalil Nurlili Elilza , N. Kiek Joseph Ngieng , Chan Wei Chze 
Published: May 2016

Abstract
Although women comprise a portion of the talent pool that makes up the oil and gas industry, historically, more men occupy roles within the sector. Additionally, challenges faced by women in comparison to men within the industry vary in terms of severity. While all areas within the oil and gas industry promote female recruitment, there is a perceived gap with respect to retaining females while providing them with career growth opportunities equivalent to those of male colleagues. A common goal amongst women within the industry is to achieve a work/life balance, to which various obstacles can be encountered related to movement to geographical locations, cultural differences, mobility, dual careers, work type, and family preferences.
Gender diversity is an important driver for employing females within in every segment of the oil and gas industry to help obtain a broader perspective while driving an organization's growth and capability. This is particularly important because women comprise a roughly equal percentage of the available workforce with equivalent levels of education to their male counterparts.
Women are capable of performing all industry roles during operations both on and offshore from finance to field engineering, operating to upper management. This paper highlights challenges faced by women within the oil and gas industry within varying roles and positions while striving to maintain a work/life balance, without sacrificing the prospects of career development. The goals is to help provide clear information related to working conditions and challenges to help increase the number of women joining the oil and gas industry.

The Petroleum Industry is Seeking Talent
Based on an annual energy outlook study (U.S. Energy Information Administration 2014), the demand for energy for the next 25 years will continue to increase parallel to the population growth, as shown in Table 1.
Tractor Production Logging in Long Cased Horizontal Wells; Operational Experience from the Al Shaheen Field, Offshore Qatar
Authors: Frans Frederic , Cuauro Antonio , Chalco Edgardo , Brink David , Ghozali Muhammad , Bounoua Noureddine 
Published: May 2016

Abstract
Production logging in ultra-long horizontal wells has long been recognized to be extremely challenging, both in terms of data acquisition and data interpretation. This paper describes the planning, execution and lessons learnt of an incident free production/injection logging (PLT) campaign completed in twelve shallow horizontal wells – water injectors and oil producers – to support the long term reservoir management strategy of the Al Shaheen field, offshore Qatar.
In this giant offshore oil field, the acquisition of even partial inflow production data is considered worthwhile. A production logging programme was therefore considered as essential.
A logging campaign was undertaken in twelve wells using tractor technology as means of conveyance, in a cased hole environment.
The key objectives of this campaign were to:Acquire dynamic flow data to improve the understanding of the reservoir dynamics.Identify where sub-optimum patterns can be improved to maximize ultimate recovery.Assess the tractor technology as a means of conveyance in long shallow cased horizontal wells.
The campaign showed that although static data are essential in understanding the flow performance of a well, they cannot solely always explain the flow profile along the wellbore. The acquisition of dynamic data is essential to understand the well behavior.
Results confirmed that in some long horizontal wells the flow profile takes place uniformly along the entire logged interval, whilst in others sub-optimum conditions such as cross flow and thief zones were identified. The paper describes how the data acquired helped to identify these latter conditions along with the repair opportunities to improve oil recovery.
This campaign proved that tractor is a viable means of PLT conveyance in shallow cased horizontal wells by pushing the limits of the technology to greater depths than coiled tubing – up to 14,550 ft – with less disturbance to flow. To maximize success in future well re-entries, completion design has been reviewed in new wells, in order to make them "tractor friendly".

Introduction
The Al Shaheen oil field in Block 5 and Block 5 Extension, offshore Qatar, consists of a stacked sequence of low permeability carbonate and high permeability clastic reservoirs at relatively shallow depths around 3,000 ft TVD. Although the field was discovered in the mid 1970's its development commenced decades later, in 1992, when Qatar Petroleum entered into an Exploration and Production Sharing Agreement with Maersk Oil Qatar (1). Today the Al Shaheen field produces ca. 300,000 barrels of oil per day and cumulative oil production exceeds 1.4 billion barrels.
Numerical Simulation of Natural Gas Transport in Shale Formation Using Generalized Lattice Boltzmann Method
Authors: Ning Yang , Jiang Yang , Qin Guan 
Published: May 2016

Abstract
In shale formations, natural gas flows either through nano-scale pores or fractures during production period. Darcy's law cannot effectively describe such transport phenomena due to its continuum assumption. Alternatively, kinetic-based lattice Boltzmann method (LBM) becomes a strong candidate of simulating organic-rich shale reservoir that contains a large amount of nano-scale pores. Among various LBM models, multiple-Relaxation-Time (generalized) LBM is considered as one of the most efficient models regarding its theories, selections of parameters, and numerical stability. For gas flow in a confined system, its molecular mean free path depends on not only the size of the confined system, but also the distance of gas molecules from solid walls. A large amount of natural gas is believed to be stored in extremely small organic pores, and adsorption in shale has a significant influence for gas transport in production. In this paper, we incorporated adsorption into generalized LBM model in order to capture the natural gas flow in organic nano-pores. Many factors are believed to control the flow mechanism in such pores, such as the size of organic pores, specific surface area, adsorptive strength, and so on. Generalized LBM results shows a great agreement with available data for high Knudsen flows between two-dimensional parallel plates. Accounted the effect of adsorption, flow phenomena are investigated by varying different controlling factors in both simple and complex structures.

Introduction
Shale gas has been becoming a significant source of unconventional natural gas. The production of shale gas mainly depends on its characteristics, such as the pore distribution, organic richness, natural/factitious fractures, etc. A significant portion of shale gas is stored in kerogen pores that are ranging 2nm to 50 nm [1, 2, 3]. Consequently, it is essential to understand natural gas flow in nanopores to be able to predict long-term shale gas production as well as shale gas reserves.
How to Improve Efficiency in Multiple History Matching: A Gas Field Case Study
Authors: Bouzarkouna Zyed , Verdiere Sophie , Jaulneau Patrice , Le Reun Juliette , Corpel Vincent 
Published: May 2016

Abstract
This paper proposes an innovative integrated workflow based on advanced history matching techniques for finding multiple history-matched models.
The proposed workflow is demonstrated on a condensate gas field. The deltaic depositional environment enhanced by normal faults created strong vertical and horizontal heterogeneities. This compartmentalization, added to the production in commingle, makes the history match particularly difficult. The proposed workflow begins by an intensive dynamic synthesis and a multidisciplinary teamwork definition of the objects to match (production rates, RFT, MDT, PLT). The potentially influent parameters and the associated ranges of uncertainty are also defined.
Early cooperation is crucial, as it sets up the scope of the history match strategy. This meticulous synthesis of static and dynamic observations enables to build the geological model and the associated history match strategy. Then, the following steps are performed:Screening: experimental design is used to highlight the most impacting parameters. Given the ranges of uncertainty defined in the synthesis, this step allows the reduction of uncertain parameters (32 in our case) to the most influential ones (13 parameters);Modeling: an innovative space filling design technique is used to define a limited number of simulations using only key uncertain parameters;Objective function formulation: different formulations are proposed to evaluate the history match quality;Assisted history matching: Proxy modeling is introduced in the framework of the objective function minimization and multiple history-matched models are obtained and then validated by the team.
Results on this field case show the necessity of a strong and coherent dynamic synthesis. The proposed workflow enables to evaluate the different impacting parameters of the model and thus finding different history-matched models. Provided physics and geology are clearly understood, this assisted history match technique is highly helpful in particular for complex fields with a large amount of data to match.

Introduction
History matching is defined as the process of adjusting a reservoir model until it closely reproduces the past behavior of the reservoir. This process is by nature an ill-posed inverse problem and thus there may be multiple different models that can all be valid. Multiple history-matched models are crucial for having valid estimations of the reservoir performance uncertainties and thus obtaining reliable predictions. However, in many history match studies, the first found history-matched model is accepted due to the tedious and time-consuming nature of the task.
History matching studies are then usually (in particular for complex reservoirs) very challenging and require an important cooperation within a multidisciplinary team including reservoir engineers, geologists and geophysicists.
An Integrated Subsurface Approach to Reveal Reservoir Connectivity for a Mature Field
Authors: Ng Khaiyi , Abdou Ali Asem Mahmoud , Hanalim Linda , Suwarlan Wahyudin , Lee ChunRhen 
Published: May 2016

Abstract
Reservoir compartments are segments that are effectively isolated by structural, sedimentologic or diagenetic barriers that hinder fluid flow laterally between compartments. However, in cases of sandstone reservoirs incising each other, the boundaries of the compartments are poorly defined and huge uncertainties are imposed on the connectivity and fluid flow behavior between them. Various geological and engineering approaches are used to work out the sand-to-sand juxtaposed reservoir compartments in Angsi Field offshore Peninsular Malaysia.
In Angsi Field, located in the Oligo-Miocene Malay basin, the I35U and I35M sandstone reservoirs from Group-I stratigraphic unit (coastal-fluvial/deltaic lobes) provide a complicated case of areal and vertical reservoir compartments. The I35U channelized blocky sand incised into I35M mouth bar sand in some parts of the field. Mapping of the interlaced reservoir compartments of both reservoirs is based on conceptual geology, log patterns and seismic data. Although the vertical spacing of the two reservoirs is below seismic resolution, the difference in quality, thickness and fluid type have allowed seismic involvement in delineating compartments.
To verify the geological findings, multidisciplinary team seeks out various methods to resolve connectivity uncertainty between the two reservoirs. Fluid gradients supported the idea; however reservoirs fluid contacts are sometimes leveled.
Existing oil producers from both reservoirs provides reliable pressure-production data for classical reservoir engineering analysis. Production Decline Curves of both reservoirs vary significantly; seemingly controlled by internal depositional architecture of each reservoir. Depletion Plots further verify no lateral communication between the two reservoirs. Finally, Material Balance proves the understanding of communication between reservoirs; oil-in-place and reserves are aligned with geological studies.
Two successful wells drilled lately based on findings from the above approach. A representative simulation model is being built for both reservoirs, incorporating the findings, to plan for further reservoir development and management strategies.
This paper shares the geological and reservoir engineering integrated approaches to resolve the reservoir connectivity uncertainties between I35M and I35U, which could be applied in similar coastal fluvial/deltaic settings. The paper also highlights the importance of multidiscipline integration in resolving reservoirs uncertainties.
Development and characterization of microsatellite primers for Chamaecyparis obtusa (Cupressaceae)
Authors: Kim Young Mi , Shin Yu Seung , Jeong Ji Hee 
Published: May 2016

Premise of the study:Although several microsatellite markers of Chamaecyparis obtusa (Cupressaceae) have been reported in previous studies, we newly developed and evaluated polymorphic microsatellite markers of C. obtusa, an economically important species in Korea as a major forestation tree species, for further genetic studies.Methods and Results:Microsatellite‐enrichment libraries were constructed according to the selective hybridization method. From this output, we obtained 10 polymorphic and five monomorphic microsatellite markers for C. obtusa. Five of these developed markers were successfully amplified for C. pisifera, a related species.Conclusions:These microsatellite markers can be valuable tools for further genetic studies of C. obtusa, and gathered genetic information may be useful for breeding program management.