bluuebunny/crossref_metadata_2025_split huggingface dataset:
Robust Regression and Band Switching to Improve DAS Flow Estimates
Authors: Park Tim , Paleja Rakesh , Wojtaszek Magdalena 
Published: October 2018

Abstract
Within the Oil and Gas industry the use of Acoustics data for flow rate estimation is increasingly being explored. One technique is to consider the total spectral power of the signal within a specific frequency range, known as an FBE. The FBE, along with measured Flow rates, can then be used to build a simple regression model to estimate the flow rate. We collect acoustic data using Distributed Acoustic Sensing, DAS, and find that the recorded FBE generally contains some corrupted data and outliers. This may be due to well shut-in periods or other physical phenomena, or it may be due to issues in the DAS recording itself. These outliers can have a detrimental effect on the calibration of any predictive model and lead to biased flow predictions. We combat this by calibrating out model using Robust Regression techniques, such as Least Absolute Deviation, which are less influenced by outliers. Another practical concern is choosing the correct frequency band for the FBE. This can be done by evaluating the model performance on a training set, however we find that the signal quality within a band can diminish over time necessitating a change in the band used. Our challenge is to find a way to identify when a band is likely to be giving poor predictions. We do this by looking at the ratios between different FBE bands, we find that under normal conditions these are highly correlated, however for certain bands this correlation is lost over time. This can be used to determine when it is time to switch to use a different band. This paper contains the motivation and results of these techniques as they are applied to flow prediction in a gas producing well which has been part of a long-term flow monitoring project.
Big Data Approach for Geological Study of the Big Region West Siberia
Authors: Olneva Tatiana , Kuzmin Dmitryi , Rasskazova Svetlana , Timirgalin Azamat 
Published: October 2018

Abstract
Big Data technologies are now being actively integrated into the oil and gas sector owing to the need to improve operational efficiency and to optimize a variety of processes. Successful projects in data processing automation have already been implemented, for example, new breakthroughs are expected in digital field modelling projects /1/.
Geological and geophysical information accumulated over decades of studies in oil and gas bearing basins and fields development is a huge amount of data; Big Data approaches can be effectively applied to them, such as data mining, predictive analytics, training of a system on the reference objects. 3D seismic data is a classic example of Big Data. Their interpretation conventionally involves approaches based on Neural Networks, various classification and clustering algorithms /2/.
According to the experts, the West Siberian Petroleum Basin being a holistic system, has unique properties such as existence of giant and unique hydrocarbon accumulations /3/. The potential of the basin has not yet been determined. The authors focused their attention on the Achimov play. Applying the Big Data approach to a regional database may allow establishing new patterns in fields distribution and will contribute to the development of new unique exploration criteria.
Numerical Studies of Helium Distribution After Injection in the Gas Reservoir
Authors: Skriabina Anastasia 
Published: October 2018

Abstract
The paper presents the results of a multiparametric analysis of the helium saturation zone after its injection into a porous gas reservoir, the dynamics of its content in a withdrawn gas mixture and the helium recovery factor (target parameters). The calculations are performed on a three-dimensional composite hydrodynamic sector model of a homogeneous anisotropic reservoir of a virtual gas deposit. Based on the results obtained, the geological and technological factors are ranked according to the absolute value of the change of target parameters when the input parameters change. The dynamics of the influence of geological and technological factors on the target parameters is described concerning different withdrawn gas volume from the initial reserves. The identified relationships can be useful for planning of the experimental helium injection and the placement of exploitation wells at underground helium storage.
The Ultra-Expansion Completion Packer Integrated with Additive Manufacturing Technology
Authors: Deng Guijun , Kendall Alex , Wakefield John 
Published: October 2018

Abstract
The oil and gas industry has paid increasing attention to the momentum of Additive Manufacturing (AM) in the aerospace and autotmotive industries because this developing technology promises improved functionality, lead time reduction, and increased product reliability. AM technology eliminates traditional design limitations imposed by conventional manufacturing. Components and sub-assemblies with complex features and shapes can be manufactured where it was nearly impossible before, often with fewer components at a lower cost. This paper presents a completion packer designed for, and built with, AM with superior performance over the conventional product. A design topology optimization process is used to liberate engineers from shape complexity limitations and generate designs that target extreme performance goals. The AM raw material is subjected to rigorous mechanical characterization throughout the manufacturing process to ensure performance and reliability during a part's service life. Finally, test well validation is conducted to verify the design successfully meets all performance objectives.
An ultra-high expansion packer designed for multiple casing weights was developed in-house. The back-up ring system of this ultra-high expansion packer was additively manufactured. The novel AM design substantially reduces the number of components for the packer back-up system while remarkably boosting its expansion capacity and pressure rating. The packer element system installed with these AM backup rings offers extreme expansion ratio, truly zero extrusion gap, and superior conformability to as-rolled casing. Testing in-house showed: High diameter expansion ratio of 111% (over 50% improvement) with low setting force compared to existing packer design of the same size,Full pressure containment in at least 5 casing weights, and10,000 psi differential pressure held above, and then below, the packing element at 300°F.
This is the industry's first completion packer that utilizes Additive Manufacturing. It is of paramount importance since AM technology enables a faster time-to-market, enhanced performance, an optimized portfolio that reduces inventory, and an alternative means of cost reduction.
Public Engagement: New Approaches to Enhance Field Planning and Environmental Compliance for O&G Development
Authors: Higgins Marian , Burnett David , Kreuter Urs , Theodori Gene , Haut Richard 
Published: October 2018

Abstract
Studies have shown the need to engage the public early in planning new energy development ventures. Many times, this may be critical to the ultimate success of that program. Based on our previous studies of community acceptance of shale development projects, we have undertaken new studies to understand better the communities’ views of development in environmentally sensitive areas. Early interviews with key stakeholders and specially conducted focus group meetings helped previously to identify the public's perceptions of such technology and showed that favorable or unfavorable views were based mostly on pre-conceived notions of potential effects rather that factual data. Those findings have shown that a developer should actively work to increase the public's awareness about a potential project. There is a strong need for those who plan new energy development to be completely transparent and to give the public knowledgeable (and credible) information about events and developments that will impact them, not just financial gains, but environmental impacts and overall effects on community.
Recognizing that sustainable development of energy resources is a sound business strategy, some O&G companies are now incorporating public engagement as part of their business strategy. However, some companies do not. Recent activity in West Texas provides an example of how companies should and should not go about energy development projects.
Development of a Large Deep-Water Gas Field in Tanzania: Subsurface Challenges and Solutions in a Frontier Area
Authors: Haugen Einar , Solymar Sabina , Pannetier-Lescoffit Severine , Reksten Kari , Lund Ida Winsnes , Mrsic Zoran 
Published: October 2018

Abstract
Significant gas discoveries have been made in deep waters off the coast of Tanzania this decade. Operator Equinor (previously Statoil) with co-venturer ExxonMobil have drilled 15 exploration and appraisal wells in Block 2 about 100 km from the shore in the southern part of the country. The objective is to develop gas resources for a large LNG project. This paper focuses on the various discoveries made and the subsurface understanding gained over the last years.
The reservoirs are all deposited as turbiditic sandstones in different geologic periods (Cretaceous to Miocene), and have a long and complicated geological history. Heavy tectonic activity including development of pop-up structures along a major strike-slip system, has impacted the depositional environment. Since some of the reservoirs have significant internal faulting, methods to analyze fault transmissibility have been key. The seismic quality is generally good, and in certain reservoirs even good enough to directly use seismic inversion dataset to map the structure more accurately. The exploration and subsurface teams worked together in improving the development concept and minimizing risk.
The youngest reservoir (Miocene) has excellent reservoir properties but special challenges with shallow overburden with top reservoir 400-500 m below the seafloor. Several studies have been completed to ensure that production wells can be safely drilled and produced during reservoir depletion, and that the reservoir seal has full integrity.
In deep water oil and gas developments it is important to demonstrate large, continuous flow units with good flow properties before investment decisions. For the Block 2 gas reservoirs understanding the aquifer strength is important for designing wells so that water production can be avoided. Detailed aquifer modeling has been made for all the main reservoirs. Modelling showed risk of water production for one of the reservoirs; however, it is expected that this risk can be mitigated by placing the planned producers high on the structure.
Deep seabed canyons are present in the area and these give important constraints on drilling locations and subsea layout including the major gas pipeline to shore. The field development is planned as a subsea-to-shore development without any fixed installations offshore. To predict the dynamic performance of such a huge and complex production system, extensive flow assurance studies have been completed.
Multiple Enhanced Mechanical Property Cements Help Prevent Pre- and Post-Fracturing Gas Migration
Authors: Kutchak Kristin , Jones Paul , Van Meter Samuel 
Published: October 2018

Abstract
"Gas migration" has been the catch phrase of the Appalachian Basin in the northeastern part of the US for years. As demonstrated in a previous study, optimal displacement efficiency can be obtained by rotating casing during the entirety of the cement operation, providing uniform cement coverage and eliminating gas migration. However, while horizontal well lengths continue to increase, the ability to maintain rotation for the entirety of the cement operation can be severely inhibited.
Conventional cement slurries are satisfactory for the majority of wells in both the Marcellus and Utica/Point Pleasant. However, while operators are pushing the limit toward a 20,000-ft measured depth, there is a growing need to rely less on industry best practices written at the onset of shale drilling and expand engineering creativity toward implementing new technologies. With rotation off the table, a service company recommended the combined use of two highly enhanced mechanical property cement slurry technologies to bridge the technology gap from a conventional cementing solution to a more "life of the well" solution.
Historically, gas migration from either the Upper Devonian and/or the Marcellus Shale has been proven to be troublesome for the northeastern part of Pennsylvania. When the challenge cannot be addressed with historical best practices, deploying new technology on hand is necessary to achieve the goal. With the more robust functionality of a low-Portland cement design and resin composite cement slurry, the service company's design team was able to combine these two technologies to deliver a dependable barrier tailored to achieve zonal isolation. Optimizing the placement of the resin-composite-based cement slurry itself was pivotal; placement across the problem zones and above the landing point of the horizontal section was necessary. Successful elimination of both pre- and post-fracturing gas migration was achieved without casing rotation during cement slurry placement. The wells were put into production, and the operator has not had to perform any costly remediation operations because the reservoir was properly isolated by means of the primary cementing operation.
Enhanced mechanical property cements were proven to be vital for alleviating the concerns of gas migration. These cement systems help prevent Upper Devonian and Marcellus wells from being reworked because of primary cement quality post-completion.
Successful Implementation of High Viscosity Friction Reducer in Marcellus Shale Stimulation
Authors: Johnson Matt , Winkler Adam , Aften Carl , Sullivan Phil , Hill W. A. , VanGilder Criss 
Published: October 2018

Abstract
Throughout multiple shale plays, high viscosity friction reducers (HVFRs) have successfully placed more proppant mass with lower treating fluid volume; thus, the industry is accelerating adoption of these treating fluids. Previous published studies have included treatments in Bakken shale and Permian Basin formations.
The characteristics of the Marcellus shale make it particularly beneficial to minimize water and gel injection into the formation. At the same time, operational constraints related to smaller footprint and pad sizes in the Marcellus region make it beneficial to reduce gel hydration equipment on location. In spite of these potential benefits, application of high viscosity friction reducers has only recently begun in the Marcellus region.
One factor delaying the introduction of HVFRs into the Northeast has been the challenging waters and brines often used in treatments. This study documents the successful introduction of a brine tolerant, high viscosity friction reducer with multiple operators in the Marcellus region.
Marcellus operators compared several different friction reducer chemistries through field trials on multiple pads. Based on measurements of surface treating pressure and proppant placement, an optimum fluid system was selected that is effective in a range of water qualities and allow increased pump rate. The friction reducer was also compared to conventional gel technology based on the same method. The brine tolerant friction reducer was found to be an effective replacement for linear gel fluids and allowed reduction of equipment on location.
A brine tolerant, high viscosity friction reducer enabled treatments to be placed with increased sand loadings, higher pump rates, and decreased surface treating pressures. The fluid system was able to work with a variety of water conditions, including brines having more than 30,000 ppm chlorides. In one case the new fluid system allowed operations to entirely move away from gel chemistry and surface hydration equipment.
The study presents measured results during the frac on one of the first applications of a high viscosity friction reducer in Marcellus shale treatment.
A Statistical Engine to Model Well Operations and Evaluate Asset Performance
Authors: Gupta Supriya , Sharma Abhishek , Verma Ekansh , Abubakar Aria , Gupta Sidd 
Published: October 2018

Summary
Holistic understanding of well operations can play a key role in optimization and maintenance of assets. The traditional process for understanding well operations mainly involves fitting a curve through all of the historical production data and extending the curve to forecast production without modeling the stochastic nature of production history, considering impact of any well interventions, or feeding any a priori information into curve-fitting workflows. This leads to unreliable production and reserves estimates which, in turn, impact the strategy and planning process for asset management. A novel workflow was developed learns the production characteristics of a well through a statistical framework using principles of signal processing and Bayesian inferences. Using this workflow, high-fidelity empirical production performance forecasts can be obtained for all the wells in the asset in an automated fashion. This novel workflow aims to significantly simplify interpretation of well operations, reduce the turnaround time for analyzing and modeling well performance, and improve the quality of reserves estimates.
Enhanced Oil Recovery in Eagle Ford: Opportunities Using Huff-n-Puff Technique in Unconventional Reservoirs
Authors: Pankaj Piyush , Mukisa Herman , Solovyeva Irina , Xue Han 
Published: October 2018

Abstract
Although hydraulic fracturing in liquid-rich unconventional reservoirs (LUR) has become a norm, the recovery factor continues to be low. Use of enhanced oil recovery (EOR) techniques in LUR has recently become more popular to improve the recovery. The objective of this study is to numerically investigate the advantages and disadvantages of the application of the CO2 huff-n-puff technique in LUR formations having complex fracture networks.
The study explores the fluid flow mechanisms for oil recovery in a naturally fractured reservoir. A calibrated 3D mechanical earth model with geomechanical and petrophysical properties from the Eagle Ford was used for the study. A complex hydraulic fracture model was used to simulate the hydraulic fracture, proppant, and fluid distribution around the wellbore. Numerical reservoir simulation on perpendicular bisection (PEBI) grids was used to capture the permeability, porosity, and conductivity distribution due to the proppants in the hydraulic fractures. The CO2 huff-n-puff technique using numerical reservoir simulation was used to determine the well performance and recovery factor arising from reservoir fluid viscosity reduction and gas expansion. The effect of fluid thermodynamics to recovery systems in the low-permeability reservoir medium was fully captured in this approach. An equation of state prepared for simulating the CO2 impact on the oil was prepared with correlating the collected downhole oil sample.
The numerical reservoir simulation study coupled with the complex fracture simulation model presents insights into a new means to improve the recovery factor (RF) in LUR through the injection of CO2. Such EOR method would be critical to increase the long-term economic benefits. The study demonstrates that that infill well requirements can be mitigated if the EOR method of huff-n-puff is utilized in cyclic modes over various time periods of production. Up to 9% extra RF was observed when the CO2 huff-n-puff technique was used as compared to production dependent only on hydraulic fracture stimulation. Parametric sensitivity on job sizes and start timing of EOR in a producing well was used to evaluate the RF. However, the hydraulic fracture geometry and the created footprint along with the time of injection have a larger effect in improving the EOR effectiveness.
The methodology demonstrates the simulation of EOR methods in unconventional reservoirs for economic assessment. The workflow demonstrates modeling CO2 flooding as an EOR technique on the full wellbore level with complex hydraulic fracture geometry. The approach can be applied to unconventional formations in other basins to improve the recovery factor.
Decision-Focused Optimization: Asking the Right Questions About Well-Spacing
Authors: Hassen Ryan A. , Fulford David S. , Burrows Clayton T. , Starley Gregory P. 
Published: October 2018

Abstract
Engineers and leaders who must decide on development strategies for unconventional resource projects face a challenging design problem. While we must make decisions on well and completion design, including well-spacing in three-dimensions, the complexity of the physical system and the interactions between these parameters can become overwhelming. The technical optimization problem can be difficult; however, asking the right questions can make the business decision clearer than it first appears.
The typical approach to design optimization problems is to build models, with a tendency toward including an ever-increasing number of parameters to describe the system in exhaustive detail. However, our uncertainty in the model parameters often makes it impossible to identify the true optimum. In this work, we focus instead on reducing the number of model parameters and capturing the impact of these critical uncertainties on our business decisions. This allows us to answer the right questions in order to define and choose the best well-spacing strategy.
For well-spacing optimization, a critical uncertainty is the relationship between the chosen well-spacing and the potential well-performance degradation, in terms of estimated ultimate recovery (EUR) and initial production (IP). Rather than attempting to describe fracture geometry and well interference from a mechanistic standpoint, we introduce a lumped parameter, the shared reservoir (SR) factor, to account for this complex relationship. The parameter distribution may be calibrated to (a) well results in a play, (b) well results in carefully selected analogue plays, or (c) simulated well results from probabilistic analyses. An example of a Monte-Carlo simulation using the uncertainty of the SR factor, as well as the mean EUR and IP, highlights the utility of the method. We also illustrate how the spacing decision impacts key risk and financial metrics, including the expected monetary value of the project, the probability of regretting the decision, and the probability of commercial success of the project.
The shared reservoir factor is proposed to capture the complex relationships between the well-spacing decision and the EUR and IP that result from this decision. Using the shared reservoir factor, we can develop simple stochastic models to clarify an otherwise frustratingly complex optimization problem.