bluuebunny/crossref_metadata_2025_split huggingface dataset:
Case Study Applied Machine Learning to Optimise PCP Completion Design in a CBM Field
Authors: Prosper Charles , West David 
Published: October 2018

Abstract
The key objective of multiple Coal Bed Methane (CBM) development operations is to determine cost effective methods to allow sustainable economic production and maximum reserves recovery. The cost of workovers as well as the associated deferred production may overwhelm the economic viability of the field. The primary reason for workovers is progressive cavity pump (PCP) system failures.
Here, we demonstrate the use of a machine learning framework that can be used to customise each workover configuration such that it optimises PCP run-life, respecting the well's heterogeneity and age. The framework can be generalised into three major parts: 1) converting the dynamic production data into a stationary surrogate model for the well; 2) the use of Gaussian process regression to create a function that estimates runlife; 3) an optimiser that will search the functional space to recommend the best completion design.
A telemetry and completion dataset for PCP run-lives from years 2014-2018 was obtained across the Surat and Bowen basins. After filtering data for completeness, 1499 PCPs remained in the cohort, of which, 895 failed during the observation period. A small portion of the original data was used as a test set.
Our work suggests that PCP run-life can be extended by taking a multivariate statistical approach to provide recommendations for customised completions and production strings per well that respect the wells’ geology and production history and thereby improve life of field economics.
Probabilistic SCAL Parameters for an Intermediate Wet Clastic Environment
Authors: Morrison Graeme , Taylor Ebony 
Published: October 2018

Abstract
In an era of automated workflow-assisted dynamic modelling, Special Core Analysis (SCAL) parameters require updating for each static realisation and evaluation at a quantifiable, probabilistic level-of-certainty. Additionally, SCAL data gaps combined with limited reliable SCAL data drive the need to establish trends and correlations from analogues.
SCAL parameters from analogue fields were selected and filtered by depositional environment and laboratory experiment type (centrifuge versus displacement). These analogue SCAL parameters were allocated to statistical bins defined by absolute permeability ranges. Statistical analysis of each SCAL parameter allocated to each permeability bin produced a probability distribution discretised by percentile. Multi-variable linear regression (MVLR) was then implemented to correlate each SCAL parameter, as the response variable, to input variables absolute permeability and percentile. SCAL correlations of reasonable to excellent quality were obtained.
The depositional environment was of second order influence in establishing these SCAL correlations. This was due to the selection of core plugs for laboratory analysis from layers of similar quality irrespective of the depositional environment, highlighting the need to select samples characterising a range of lithology and reservoir quality. Centrifuge experiments of water displacing gas were discarded as unreliable due to the compression of the gas phase by the experimental technique.
The multi-variable linear regression methodology enabled SCAL parameters to be determined as a function of both absolute permeability and probability. This approach should enable an automated implementation of SCAL parameters within each dynamic model realisation.
Reservoir Architecture Analysis of Delta Front and Its Control on Remaining Oil Distribution of S Oilfield in Bohai Bay Basin
Authors: Li Junfei , Liu Xueqi , Gao Zhennan , Shang Baobing , Xu Jing 
Published: October 2018

Abstract
After more than 20 years’ development, S oilfield has entered high water cut stage. The layer contradiction is prominent and the water flooding condition is complex, which result in the complex decentralized state of the remaining oil. In order to determine the remaining oil distribution to guide the comprehensive adjustment of the oilfield, the reservoir architecture analysis of delta front was conducted.
Based on the core, seismic data, dense well logging data and production performance data, the reservoir architecture of delta front in Dongying group is characterized with hierarchy process, model guidance and numerical simulation methods. In the paper, the distribution style of interlayers in single mouth bar is discussed. The distribution feature of the remaining oil under the control of interlayers is analyzed.
It shows that multiple main channels form continuous mouth bar complex and single mouth bar develops several accretions. Interlayers in single mouth bar express in two forms: the foreset type along the source direction and the arch type perpendicular to the source direction with a low angle from 0.4° to 1.0°. Along the source direction, remaining oil gathers inside accretions whose injection-production does not correspond under the control of interlayers. And the remaining oil is enriched at the front of accretion. In the vertical source direction, the remaining oil accumulates in the high part of accretions. Under the guidance of remaining oil distribution characteristics controlled by reservoir architecture, one horizontal well was deployed. The average output is more than 100m3/d and the water cut is under 30%, which indicates the effect of this reservoir architecture analysis work.
The successful implementation of the horizontal well demonstrates the vital function of the reservoir architecture research for this kind of mature oilfield. This will also be one promising research direct for the overall adjustment and remaining oil tapping.
A Novel Downhole Gas Separator in ESP Systems
Authors: Wang Qinghua , Liu Yonghui , Yang Junzheng , Cui Mingyue , Qi Dan 
Published: October 2018

Abstract
For Electrical Submersible Pump (ESP) systems in high-GLR wells, presence of gas inside ESP results in the degradation of hydraulic head. As a remedial tool to improve the ability of handling gas-liquid mixtures, Downhole Gas Separator (DGS) is of crucial importance. However, conventional DGS has limited capability in separating free gas and a maximum separating efficiency of 45%. It can't meet the field applications to a wider range of flow conditions and different pump models. Therefore, the paper proposed a solution to improve gas handling ability of DGS to expand its application.
Combining centrifugal separation method and gravity separation method, three-annular design was proposed to address the problem of two-stage separator with fairly long length. In the new design, a device is used to accelerate the fluid for higher velocity flowing into the annular between the spiral outer pipe and the central pipe. Then, the helical blades in the annular separate the gas-liquid mixture, leading gas attaching on the out wall of the central pipe and subsequently discharge into casing through the vent holes. The liquid attached on the inner wall of the spiral outer pipe flows reversal because of gravity. Afterwards, liquid is forced into the central pipe through the drainage holes and then flow into the ESP. In order to improve separating efficiency, the structure of helical blades, including distance and number of thread for centrifugal separator was then optimized by numerical simulation. In addition, an experimental study was conducted in different GLR and deviation. The experimental results show separating efficiency ranges between 88% and 96% while the conventional is under 60%. Furthermore, the separation efficiency decreases with the increasing of deviation, and maximum deviation of the new separator can be applied is 50°[1].
The novel DGS provide an economic solution for ESP application in gassy reservoir with low cost and power; since the new design greatly shorten the length of traditional two-stage separator.
A Review of Recent Advances in Cost-Effective Infrastructure System Design of the CO2 Distribution to CCS Injection Wells
Authors: Dashti Hossein , Underschultz Jim , Garnett Andrew , Honari Vahab , Sedaghat Mohammad , Rudolph Victor 
Published: October 2018

Abstract
CO2 transport from capture sources to storage sites is one of the leading parts of the carbon capture, and storage (CCS) infrastructure that needs to be optimized in order to reduce the capital, operating and maintenance (O&M) costs. This paper conducts a systematic overview of CO2 transport and identifies the knowledge gaps with a view for application to optimal CCS Hub design. The findings show that much research has been focused on the engineering and economic consequences in pure CO2 streams while in most real field studies the captured CO2 is accompanied with trace impurities that can affect the "intelligent" cost model's confidence to estimate CO2 pipeline costs. The impacts of different topographical conditions in current models on the economic pressure drop and inlet pressure is another challenge that has received little attention in the literature. Most cost-effective pipeline systems described in the literature, are based on the simple point-to-point design while the capture of CO2 from multiple sources and transport to multiple distributed CCS injection wells is an issue for the industrial-scale rollout of CCS. The lack of sufficient studies on the flow variations within CO2 networks is the last discussion in this research review. Further, there have been several cost models reported in the literature, and most of them are based on the costs of the natural gas pipeline infrastructure. However, the higher operating pressure of CO2 and the various impurities in CO2 streams from capture plant may require construction material specifications that will affect cost models. A systematic understanding of how CO2 pipelines contribute to CCS chain economics is still lacking. While many optimization challenges have been solved for natural gas pipeline networks, there are different thermodynamic behaviors for CO2 that require further optimization. The potential minor impurities that could occur in CO2 pipelines such as water (H2O), nitrogen (N2), oxygen (O2), hydrogen sulfide (H2S) and methane (CH4) can add complexity compared to the transport of natural gas.
The Lean Fluid Lifecycle: Optimizing Consumption and Waste in Hydraulic Fracturing Operations
Authors: Jukes Rachael 
Published: October 2018

Abstract
This paper presents a case study reviewing the systematic optimization of fluid transport, consumption and waste in large hydraulic fracturing development campaigns. With a focus on reducing consumption, re-thinking transport, and creating value from waste fluid through recycling and reuse, the methodology applied has resulted in very real gains in economic, environmental, social and safety outcomes. The objective of this case study is to provide practical information and guidance for planning, execution and ongoing optimization to not only reduce the footprint of hydraulic fracturing activities but also reduce cost.
By applying the methodology within this paper, the following was achieved over a 90 well development program: Fluid transport via trucking to wellsite virtually eliminated through use of the water production gathering network;Total fluid requirements reduced by 50%;Chemical costs reduced by 35%;Fluid disposal volume via trucking reduced by 95%; andFluid waste disposal costs reduced by 90%.
While the case study presented is based on a coal bed methane (CBM) development where between 3,000 to 6,000 barrels of clean fluid was required per well, some or all of the methodologies may be applied to shale and conventional markets. With trends in stimulation volumes within the United States shale plays increasing more than threefold in recent years to upwards of 160,000 barrels per well (Dunkel, M. R., 2017), it is the responsibility of the industry to ensure that further growth into Australian shale markets – such as in the Northern Territory – are managed sustainably. For optimal results, fluid logistics cannot be an afterthought in development planning left to the hydraulic fracturing operation, but a key consideration in the overall project strategy.
Vertical Minihole Creation and Fracturing Technology for Completing Unconventional Wells
Authors: Surjaatmadja Jim B. , Abass Hazim H. 
Published: October 2018

Abstract
The success of shale development has inspired new technologies to economize the extensive fracturing treatments necessary to complete extremely low permeability commercial wells. While bi-wing fractures are typically achieved during conventional fracture stimulation applications, it is often necessary to generate a complex fracturing network for most formation types encountered in very low permeability unconventional wells. Therefore, for source shale formations, the emphasis is on connectivity to natural fractures to establish an adequate stimulated reservoir volume (SRV).
This paper discusses a new approach where improved initial wellbore-to-formation connections can be achieved by creating extended large diameter vertical cavities from the lateral as an effective fracture initiation point. This provides improved connectivity to the stimulated reservoir network both during stimulation and production. Additionally, this paper discusses the unique mechanics of the new procedure to generate a large connected SRV (CSRV) in unconventional formations, the technique, and the resulting benefits in fracture stimulation of resource shales or in ultra low permeability sandstones or carbonates as well as coal reservoirs. This new approach is fairly easy to implement, can be applied with limited hydraulic horsepower availability, and the impact could be substantial.
Investigation of Partial Miscibility Between Gas Condensate PVT Samples and Oil Based Mud
Authors: Bon J. , Ortega P. A. 
Published: October 2018

Abstract
The measured PVT properties of gas condensate reservoir fluid samples collected while logging from wells drilled with Oil Based Mud (OBM) will often suffer due to contamination from the base oil. The objective of this work was to investigate the effects on reservoir fluid PVT properties of certain components dissolving preferentially into the gas stream and from the reservoir gas into the base oil.
Using a modified slim tube set-up, a reservoir gas was contaminated with base oil from an OBM. The two fluids interacted within a porous media under reservoir conditions by injecting the reservoir gas into the slim tube that had been pre-charged with base oil. After displacing all liquids, gas samples were collected again under reservoir conditions creating a batch of contaminated samples.
Using the results of compositional and PVT data obtained from contaminated samples at the back end of the slim tube and the original clean reservoir gas, a fully compositional numerical simulation model was created to simulate the experimental results.
During the experimental work, after extended flow of the reservoir gas through the modified slim tube we noticed that the reservoir gas was being produced leaner, indicating that the heavier components of the reservoir gas were staying on the porous media.
Using the compositional simulation model, we tested the sensitivities of conditions under which heavy end stripping of the gas condensate components may occur and how to obtain cleaner reservoir fluid samples faster from wireline formation testers in OBM drilled wells.
The modelling work indicates that when the reservoir gas and base oil are more miscible cleaner samples are obtained sooner.
Throughout this work we have been testing the idea that, if not completely miscible, the near wellbore region will retain an immobile phase of base oil and that this stationary fluid may hold back the heaviest components native to the reservoir gas. Furthermore, perhaps by altering the properties of the base oil, miscibility between the reservoir gas and base oil can be increased and improved samples obtained faster.
Practical Workflow to Estimate Expected Ultimate Recovery in a Fracture Stimulated Multi-Layered Tight Gas Reservoir: A Case Study from Big Lake Field
Authors: Guillen Falcon G. E. 
Published: October 2018

Abstract
A robust estimation of the Expected Ultimate Recovery (EUR) for fracture stimulated multi-layered tight gas wells, early in the production life of the wells, is the cornerstone for a meaningful project economic analysis, reserves classification and future field development plan, however, it actually presents significant challenges to reservoir engineers.
The complex flow dynamic of a tight gas reservoir causes that the direct application of the most commonly used reservoir engineering techniques to characterize Original Gas In Place (OGIP) such as Static Material Balance (P/Z vs Gp plot) and Flowing Material Balance (FMB), and EUR estimation such as Decline Curve Analysis (DCA) can only provide reliable results within an acceptable level of uncertainty when significant production decline data is available (minimum 6 to 9 years of production history in the case of Big Lake wells). This makes early predictions of future production decline behavior hence EUR highly uncertain, sometimes even unrealistic and very subjective to the analyst, with significant potential impacts.
The objective of this work is to present a practical workflow that provides suitable constraints to be applied to the otherwise poorly constrained DCA technique for EUR estimation by making appropriate adjustments to the results obtained from the standard reservoir engineering techniques when applied to the early production decline data of multi-layered tight gas wells, based on relevant correlations from a detailed production and reservoir analysis of numerous field cases from the Big Lake Field in the Cooper Basin.
Specifically, the study illustrates: (1) that the OGIP from P/Z determined early in the production life of a well, although using imperfect Build-Up pressures (static pressure values taken at the well which are still building pressure due to reservoir characteristics and sampling period), can be reasonably corrected to better represent the long term connected OGIP to the well, through a correlation between P/Z and FMB analysis on existing wells. (2) The integration of Production Logging Tests (PLT) data and petrophysical properties provides important inputs in order to better characterize the vertical heterogeneity of the reservoirs and simulate the aggregate Recovery Factor (RF) in a multi-layer production scenario. (3) A more constrained multi-segment DCA, constructed honoring the results from point 1 and 2 better represents (within 6% deviation) the production forecast of over 40 wells in the Big Lake Field after a year and half of additional production and it is expected to be a close approximation of the EUR of the wells (assuming current operating conditions).
Effect of Low Pumping Rate on Mud Displacement Efficiency and Pumping Pressure During Cementing of Oil Wells
Authors: Tcibulskii Mikhail , Akhmetov Marsel 
Published: October 2018

Abstract
The Vostochno-Messoyakhskoe field is the northernmost active continental field in the Russian Federation (Fig. 1). This field is located 250 km from the Arctic Circle, in the arctic climatic zone. Full production drilling only began in 2015 because of the field's geological complexity and lack of transportation structure. Weather conditions, such as strong winds and extremely low temperatures, can be hazardous to personnel and equipment. Additionally, this oil field has permafrost zones (400m from the surface) and low formation temperatures at the production zone. Also, because of permafrost zones, there is a high risk of thawing the wellhead formation. These conditions significantly affect which technologies can be applied during drilling and completion of the wells. Therefore, special cement designs are necessary to help reduce risks associated with low temperatures and permafrost zones in the Vostochno-Messoyakhskoe field.
Production is further complicated by a gas layer at 720 to 820m true vertical depth (TVD) and high formation pore pressure. This can make the cement operations with the production casings difficult. While the TVD of the casing landing is not relatively deep, the measured depth (MD) in extended reach drilling (ERD) wells is significant (Fig. 2). ERD wells can challenge cement displacement efficiency (Sabins, 1990). Mud removal efficiency may not be enough to create a high-quality cement barrier and isolate formations from gas migration. Poor mud removal can affect future life of the wells and crude oil production. To perform remedial jobs, it is necessary to stop production for several days. Due to experience in performing remedial jobs in the Messoyakhskoe field, it is usually necessary to perform a few attempts of the remedial cementing operation to reach positive results. Therefore, the operator decided to utilize hydraulic packers to create a second barrier between the surface and production casings to help prevent gas migration to the surface, save time associated with remedial operations, and extend the life of future wells.
An Investigation into the Benefits of Combined Polymer-Low Salinity Waterflooding
Authors: Santo Asmoro , Muggeridge Ann 
Published: October 2018

Abstract
Polymer flooding and low salinity waterflooding are two different but potentially complementary Enhanced Oil Recovery (EOR) techniques. Polymer flooding improves fractional flow and sweep efficiency by improving the mobility ratio for the displacement. Low salinity waterflooding improves pore scale displacement efficiency by changing the wettability of the reservoir rocks toward more water-wet. Reduced salinity water is often used in polymer injection to reduce hydrolysis however the water salinity in this case is typically higher than that needed to obtain a true low salinity effect. This paper describes the outcomes of a systematic study into the potential benefits of combined polymer-low salinity waterflooding versus polymer-high salinity waterflooding, polymer-reduced salinity waterflooding and conventional waterflooding.
Numerical simulation, validated against analytical solutions, was used to evaluate the relative performance of these processes. The impacts of layering and reservoir heterogeneity were investigated using two-dimensional (2D) and three-dimensional (3D) reservoir models. Sensitivity studies of injected water salinity and the start time of injection were carried out in each of these models. Outcomes were compared against the recoveries and water cuts predicted using a one-dimensional (1D) analytic solution for the EOR processes to evaluate the impact of sweep versus displacement efficiency on incremental oil recovery and water cut.
Combined polymer-low salinity waterflooding shows an improvement in recovery and reduction in water cut compared with the other EOR processes in all cases. We show this is partly due to improving the fractional flow (increasing shock front saturation) but is also due to both the leading and trailing shock fronts in polymer-low salinity waterflooding being more stable than in the other EOR processes, reducing the possibility of viscous finger growth and thus increasing performance. The highest incremental oil recovery is observed when the injected water salinity in the combined polymer-low salinity waterflooding is reduced to below the low salinity threshold. It is clearly beneficial to reduce the water salinity to this low level rather than just to a salinity where hydrolysis is prevented. The injection of the combined EOR technique in tertiary mode, particularly at 75% water cut after performing high salinity waterflooding, exhibits an incremental oil recovery of between 15 and 42% and a reduction in water cut of between 11 and 48% at 1.0 pore volume injected (PVI).
This is the first systematic investigation into the performance of combined polymer-low salinity waterflooding compared with conventional waterflooding, low salinity waterflooding, and polymer flooding with reduced salinity water. It provides a clear insight into the benefits of combined EOR process justifying the need for field scale pilots and further laboratory studies.