bluuebunny/crossref_metadata_2025_split huggingface dataset:
Multi-Scale Digital Rock Quantitative Evaluation Technology on Complex Reservoirs
Authors: Jin Xu , Yu Chen , Wang Xiaoqi , Liu Xiaodan , Li Jianming , Jiao Hang , Su Ling 
Published: October 2018

Abstract
High heterogeneity and small pore throat characterize the mineral compositions of complex reservoirs. The evaluation of the effectiveness of reservoir space, the detailed evaluation of the rock structure, and the evaluation of fluid occurrence and migration all determine the possibility of oil and gas exploration within complex reservoirs. The technologies and workflows used for the multi-scale digital rock evaluation of complex reservoirs analyze the reservoir space (i.e., the pore throat and fractures), the rock structure (i.e., mineral and organic matter), and fluid characteristics. For the reservoir space, two-dimensional large-area analysis is sufficient to evaluate heterogeneity and multi-scale selection across 6–7 orders of magnitude. Three-dimensional space distributions of pore throat and fractures are precisely depicted through a combination of multi-scale CT and FIB-SEM. The developing agent facilitates the analysis of the micro-pore connectivity effectively. For the solid components, a quantitative evaluation of mineral composition and distribution is possible using Qemscan, and organic matter morphology and distribution are quantitatively assessed using the three-dimensional FIB-SEM. To characterize the fluid, charging effects may aid in the identification and characterization of residual, organic fluid traces. We perform the physical modeling of shale oil occurrence and migration by using nano materials that have adjustable pore sizes, adjustable wettability, and adjustable surface microstructure to understand the impact that each factor has on shale oil occurrence and the lowest pore sizes in which fluid can migrate. We use molecular simulations to observe oil and gas aggregation mechanisms and the diffusion potential in inorganic and organic nano pores. To supplement the conventional reservoir analysis, multi-scale digital rock evaluation, and its specific applications, provide technical proof for effective complex reservoir assessment, including shale oil and gas reservoirs, tight sandstone oil and gas reservoirs, and deep oil and gas reservoirs, as well as a quantitative oil-gas probability evaluation.
Impact of Laboratory Testing Variability in Fracture Conductivity for Stimulation Effectiveness in Permian Deep Coal Source Rocks, Cooper Basin, South Australia
Authors: Fraser Samuel A. , Johnson Jr. Raymond L. 
Published: October 2018

Abstract
Hydraulic fracture stimulation of low permeability source rock-reservoirs is increasing in the industry and low-permeability, deeply buried coals, "Deep Coals," represent an underdeveloped resource in the Cooper Basin of South Australia. Numerous treatments have been performed with overall technical success but varied productivity. Thus, it was important to understand the potential hydraulic fracture conductivity in the Permian Deep Coal play by evaluating the key treatment variables affecting post-stimulation results.
Proppant conductivity tests were conducted on samples from two preserved Deep Coal cores of differing thermal maturity under laboratory conditions, replicating reservoir conditions. Varying concentrations and mesh sizes of lightweight ceramic (LWP) and sand proppants were tested at 250°F. All tests were subject to closure stresses observed in the field, ranging from 2,000 psi to 10,000 psi, using representative hydraulic fracturing fluids. Results revealed a significant conductivity difference between the two coal thermal ranks due to variation in mechanical properties
Varying proppant concentration tests revealed that effective conductivity at higher stresses occurs within a narrow window. This window is a balance between insufficiently low concentration resulting in significant conductivity loss, and excessive, non-linear conductivity gains in higher concentrations. Results from these studies are integrated into a hydraulic fracture and reservoir stimulation modelling software to up-scale the observed results versus the laboratory data. Finally, laboratory results helped explain trends for success in stimulation design based on observed post-frac, flow rates.
An Experimental Study of a Novel Parallel Pipe Separator Design for Subsea Oil-Water Bulk Separation
Authors: Skjefstad Håvard Slettahjell , Stanko Milan 
Published: October 2018

Abstract
As oil fields mature, the produced water content of the production stream will often increase over time, and produced water management will eventually become a bottleneck in production. Subsea separation of produced water enables prolonged lifetime of brown field installations, increased recovery rates and more energy efficient production. In addition, implementation of subsea water separation will also enable future tie-ins to existing facilities, and reduce the need for new and expensive transport lines. Existing installed subsea produced water bulk separator technologies are limited to gravity and compact gravity vessels, such as Troll and Tordis, and the Marlim pipe separator. These are large installations, which are costly to manufacture, transport and install. In addition, the gravity and compact gravity vessels are not suited for deep-water installations, and there is a need for novel solutions to both reduce the weight and size of bulk water separators, making the technology more attractive for new business cases.
In order to investigate improved subsea bulk water separation technologies, a multiphase oil-water test loop has been developed at the Norwegian University of Science and Technology (NTNU). Facility test fluids are ExxsolD60 and distilled water with wt%3.4 NaCl. In this paper, a new separator design, utilizing multiple parallel pipes will be presented. The design allows reduction of required wall thickness at large water depths, shorter residence times and hence a shorter separator length compared to traditional gravity based technologies. Initial performance data of a constructed medium scale prototype will be reported, including separation efficiency estimations over a range of flow rates, water cuts (WC) and water extraction rates (ER). Tested flow rates vary from 250L/min to 750L/min at 30%, 50% and 70% WC. Water extraction rates are varied from 50% to 100% of the inlet water rate.
Based on this initial test campaign, the concept proves promising, displaying good separation efficiencies (&gt;98%) for both water continuous and oil continuous inlet flows at moderate flow velocities. At higher flow rates, performance decreases, and water extraction rates must be limited in order to maintain high efficiencies. Photos of flow conditions at the water outlet are included, providing a visualization of the occurring two-phase flow phenomena inside the separator.
The presented concept adds to an expanding portfolio of proposed subsea separation solutions, and displays a new way of utilizing parallel pipes to achieve oil-water bulk separation.
Discrete Net-to-Gross Truncated Gaussian Simulation: An Alternative Modelling Approach for CSG Unconventional Reservoirs, Bowen Basin, Eastern Australia
Authors: Rattazzi Simone , Hansen Alan 
Published: October 2018

Abstract
Building a representative static model for predicting and monitoring performance of coal seam gas fields presents several complex and unique challenges. The individual reservoirs possess very different coal architectures, often with highly complex seam splitting, amalgamating and structural deformation. The objective was to develop an alternative approach which honoured log and core data capturing both the lateral heterogeneity and the vertical signature of the Bowen Basin coals, Central Queensland.
In some areas of the Bowen Basin, coals can be thick and laterally continuous; picking the top and base of each seam works well in small models with homogeneous coals. As seam geometries begin to increase in complexity and coals become more heterogeneous in nature with thinner seams in multiple packages, then a net-to-gross (NTG) approach is often more appropriate. Each method has its merits. The former approach describes the reservoir architecture but implies a certain degree of confidence in coal correlation; in a vast field with complex seam splitting and merging with abundant drilling data, it may not be a practical technique. The later method (NTG) disregards coal seam architecture and reservoir connectivity.
The proposed workflow is designed to take advantage of both NTG characterization and facies modelling technique using a combined hybrid approach. The process is operating on a relatively coarse layered chronostratigraphic framework in which coal is captured as contiguous discrete-NTG "facies". The utilization of the Truncated Gaussian model ensures the contiguity of facies and mimics transitions between coals and carbonaceous mudstones (or other transitional interburdens). With the adoption of facies vertical proportion trends we are able to replicate a similar coal seam signature laterally away from the well bore. The definition of a categorical coal model allows the proper scaling of seams with different coal quality characteristics.
With the successful geocellular model re-construction of two historical Coal Seam Gas (CSG) fields in the Bowen Basin, the discrete-NTG Truncated Gaussian Simulation approach has proven to be a valid alternative CSG modelling technique.
Application of Managed Pressure Drilling on a Semisubmersible Tender-Assisted Rig to Address Drilling Challenges in HPHT Gas Condensate Wells, Offshore Vietnam
Authors: Dalgit Singh Harpreet Kaur , Ta Quoc Bao , Chai Yong Tan , Khanh Do Van , Cuong Nguyen Xuan , Tung Hoang Thanh , Nam Truong Hoai , Hai Ngo Huu , Tuan Dang Anh , Bao Trinh Ngoc , Hung Tran Nam , Cuong Nguyen Pham 
Published: October 2018

Abstract
High-pressure, high-temperature (HP/HT) environments often present kick and losses scenarios. Bien Dong POC Well-1 serves as an example of such scenarios with a very narrow-pressure operating window. Operational pressure challenges prohibited achieving the objectives.
While drilling the Bien Dong Well-1, the well encountered ballooning issues, high pore pressures, and a narrow window. As part of remedial actions when drilling Bien Dong Well-2 & Well-3, the Bien Dong POC drilling team decided to deploy MPD technology with constant bottomhole pressure and early kick-loss detection capabilities.
By applying MPD techniques, the team drilled the 12-1/4-in. hole section with the lowest possible mud weight to accommodate the narrow drilling window. Drilling the well sections to total depth (TD) took only 10 days in Well-2 and 14 days in Well-3. MPD also allowed stripping out of the hole with surface backpressure (SBP) instead of pumping out of the hole to minimize swab once in shoe, which reduced trips for considerable rig-time savings.
The wells were drilled using MPD technology on a semisubmersible tender-assisted rig. A comprehensive rig survey was conducted during the planning phase of rig construction. The survey outlined the permanent installation of the MPD system, including an automated MPD choke manifold and docking-station rotating control device (RCD). The MPD equipment was integrated into the rig on a flexible plug-and-play basis to enable easy rig up and rig down. The integration also enabled moving the equipment between wells when the rig skids and during the MPD operation. The success of MPD operations came through cooperation with team members, experience from lessons learned, and excellence in rig crew performance on well after well.
This paper will discuss how MPD technology led to campaign improvements and cost savings throughout Bien Dong Well-2 and Well-3.
Brittleness Index Prediction via Well Logs and Reservoir Classification Based on Brittleness
Authors: Feng Cheng , Deng Xili , Yin Wen , Wang Zhenlin , Mao Zhiqiang 
Published: October 2018

Abstract
Tight oil reservoirs need fracturing to obtain industrial productivity, and brittleness of rock has an important effect on fracturing. For oil reservoirs of the Permian Lucaogou Formation in Jimusar Sag of Junggar Basin, in order to predict brittleness index accurately, 19 typical tight oil core samples were selected and the related parameters of petrophysics and rock mechanics were measured at first, it is found that the static and dynamic brittleness indices vary greatly. Then, based on the static and dynamic experimental results of core samples and previous research results, the ratio of static and dynamic brittleness indices is constructed, it has a well correlation with porosity and clay content. Hence, according to the porosity and clay content correction, the static and dynamic conversion model of brittleness indices is built. The predicted results of the model are in good agreement with the experimental results. Then, on the basis of the composition, structure and deformation mechanism, the reservoirs are divided into three types via rock brittleness. The stress-strain curves of good, poor and moderate brittleness reservoirs are respectively linear, concave and "S". The static brittleness index-Poisson's ratio cross plot is built to classify the reservoirs. When the static brittleness index is greater than 85 and Poisson's ratio is less than 0.2, the reservoir shows good brittleness. When the static brittleness index is less than 40 and Poisson's ratio is greater than 0.24, the reservoir shows poor brittleness, and when the static brittleness index and Poisson's ratio are between them, the reservoir shows moderate brittleness. Finally, the static and dynamic brittleness index conversion model and reservoir classification standard are applied to formation evaluation in the study area, showing good application results. The research results are of guiding significance for the conversion of static and dynamic parameters of tight oil reservoirs, the selection of fracturing layers and fracturing operation schemes.
Geomechanics in Unconventional Reservoir: A New Approach to Drilling Integrating Advanced Acoustic Measurements and Formation Evaluation
Authors: Chatterjee Chandreyi , Reyes Allan , Lujan Violeta , Majumdar Chandan , Prasad Kanchan , Kumar Arvind 
Published: October 2018

Abstract
The Spraberry Trend oil field produces from a single enormous sand interbedded with shales, and typically pinch-out up dip. Being deposited in submarine channel systems and their associated fans, the sands are with very low porosity and permeability, both of which impede oil recovery. Oil has accumulated in stratigraphic traps, migrating upward from source rocks until find impermeable barriers. However, the natural fractures further complicated the hydrocarbon flow and pose drilling challenges in this field. A client has planned to drill deviated wells in Spraberry Trend area. They aimed to drill the wells with less drilling issues and Non-Productive Time. Wellbore instabilities and mud losses are more than in all wells drilled in Permian Basin and more specific in the prolific and acclaimed Midland Basin. Those drilling events are crucial to defining if the well will reach the goals and plans developed by geoscientists, drillers, and petroleum engineers. Decisions like casing points, open hole intervals, kick-off-points, curve sections, and finally landing points are very impacted if wellbore instabilities are present and this management is difficult to mitigate. To boost the drilling campaign, it was important to take control of the borehole problems and it was achieving through mud weight optimization. The laminated reservoir showed that isotropic stress model would not give correct stress parameters. Thus, a new workflow is being inherited to cogitate TIV (transverse isotropy vertical) stress model for wellbore stability analysis. TIV anisotropy analysis was performed on a representative vertical well using advanced acoustic measurements and the model was calibrated with post-drill events. This calibrated model gives the stable mud weight window for four planned laterals. This paper will highlight how a geomechanics-based approach, integrating advanced acoustic measurements, has significantly improved drilling rates by reducing drilling-related problems. The wells were drilled keeping the mud weight at the lower limit of the stable mud weight window. This led to faster drilling with an average rate of 1,300 ft/day. Reduction in wellbore instability issues has led to considerable reduction in time spent on reaming, mud circulation, cleaning tight spots, etc. This effectively reduced Non-Productive-Time and rig cost. Wellbore stability analysis incorporating anisotropic stress from advanced acoustic measurements has helped most right mud weight estimation and thereby drilling the wells at a faster rate in the unconventional reservoirs.
Novel Eco-Friendly Cationic Surfactant for Improving Oil Recovery from Carbonate Reservoirs
Authors: Valluri Manoj Kumar , Cain Robert , Lalgudi Ramanathan 
Published: October 2018

Abstract
Cationic surfactants have been proven to be highly effective in improving oil recovery in carbonate reservoirs with low surfactant loss due to adsorption. However, toxicity concerns and the cost of formulation have impeded their widespread usage in the oil and gas industry. Our study focuses on developing an economic and environmentally friendly solution to this challenge.
Soybean oil was used as the raw material to synthesize a surfactant that had 3 cationic sites. The resulting formulation, in conjunction with an ethanol co-solvent, was tested for emulsion and rock-fluid behavior with dolomitic reservoir rocks and oil sampled from a producing well in Morrow County, Ohio. Interfacial tension (IFT) and contact angle measurements were conducted to characterize rock-fluid behavior of the surfactant. Estrogenic and anti-estrogenic activity were evaluated to help understand its environmental impact. Finally, oil recovery was measured using spontaneous imbibition tests and the results were compared to those obtained using cationic and anionic surfactants supplied by a commercial vendor. All the tests were conducted at standard atmospheric conditions except the imbibition studies, which were conducted at reservoir temperature.
Our soy-based surfactant reduced the IFT by 60% and changed wettability from oil-wet to water-wet at concentrations lower than 3 gpt. No estrogenic or anti-estrogenic activity was detected for the surfactant at very high testing concentrations. The soy-based surfactant outperformed both the commercial anionic and cationic surfactants in imbibition tests recovering 35% of the oil originally in place (OOIP) inside the rock while the commercial cationic and anionic surfactants recovered 27% and 18% of OOIP, respectively.
These encouraging results suggest that our soy-based surfactant has the potential to provide cheap and eco-friendly solutions for improving oil recovery from tight carbonate reservoirs in addition to other potential near-wellbore performance enhancements that are currently being investigated. We believe this novel additive has the potential to solve oil recovery and near-wellbore issues at a lower cost to the operator and lesser impact on the environment compared to the products in use today.
Sand Conglomeration Trial as an Alternative to Sand Control: Case Study from Mahakam Delta, Indonesia
Authors: Styward Boris , Wijaya Ryan , Manalu Dasa , Wahyudhi Fransiskus , Setiawan Thomas , Dading Albert Malvin , Rizal Muhdi , Widarena Tri Maharika , Lukman Geraldie , Primasari Indah , Merati Putu Astari , Hezmela Rizka , Fuad Muhammad , Nwafor Chidi , Hai Liu , Singh Pratyush 
Published: October 2018

Abstract
Pertamina Hulu Energi operates numerous wells that produce gas from unconsolidated, tight sands in the Mahakam Delta. The company maintains a zero-sand production policy as its surface facilities are not designed to handle sand. If sand is produced, the wells are choked back, thus impairing the overall field production. To fix sand and fines in place, the primary sand control method used has been multizone single-trip gravel packing, sometimes in conjunction with sand consolidation or ceramic screen for noneconomic zones. However, the current state of the Tunu shallow portfolio renders sand consolidation infeasible, as more than 50% of the remaining reservoirs are either low-stakes (i.e. not economical) or are located in low-permeability zones. Against this backdrop, sand conglomeration is being considered as an alternative solution to produce the remaining reservoirs. A trial has been conducted to assess the feasibility of using sand conglomeration technology as an alternative to sand consolidation in the Mahakam Delta, the results of which will be reviewed in this paper.
An Integrated Cement Design and Evaluation to Reduce Downhole Sanding Risk
Authors: Cadogan Paul , Seth Kapil , Crabtree Richard , Beales Vincent , Alsayed Ayssar , Cheong Boon 
Published: October 2018

Abstract
As subsea completion and tie-back development plans become more plentiful, the impact of sand failure on production often severely impacts the economics of a gas field. The integrity of downhole, subsea and facility equipment may be compromised due to excessive sand production which can potentially lead to catastrophic failure. In cased and perforated sand-face completions, good cement sheath coverage across the casing can act as the main defense against excessive sand production. An integrated approach involving cement design, execution and subsequent evaluation is therefore critical to minimise sand production during the life of the well.
In this paper, we outline the evolution of the process of cement design, placement and evaluation used in a multi-well development campaign by an operator to achieve quality cement placement across the entire well length of the sub-horizontal wells.
At the commencement of the drilling campaign, perforation intervals were initially limited due to the combination of high levels of sanding risk and interpreted cement log. To limit unperforated sections, a dual pronged approach was instigated looking at both cement design and operations, and cement bond log evaluation. As the campaign progressed, both elements were improved leading to an overall improvement with respect to perforation length. Challenges overcome included lost circulation in fractured formation, poor mud removal in extended horizontal casing, gas migration into the cement sheath, the presence of micro annuli by the loss of acoustic coupling due to oil-wet casing and test pressure applied between cementing operations and evaluation.
In this paper, the entire cementing program design, placement and evaluation workflow will be explained with specific examples from the field development. Special focus will be given to the evaluation of the cement using state-of-the-art high-resolution wireline technology leading to a reduction in interpretation uncertainty through advanced workflows. Finally, examples will be provided where the inputs from the logs were integrated with both drilling and petrophysical data to evaluate the sanding propensity, thus allowing the operator to confidently perforate high-risk zones and ultimately improving well productivity.