bluuebunny/crossref_metadata_2025_split huggingface dataset:
Characterizing Pores and Pore-Scale Flow Properties in Middle Bakken Cores
Authors: Karimi Somayeh , Kazemi Hossein 
Published: October 2017

Abstract
To understand the flow and transport mechanisms in shale reservoirs, in 2014 we needed reliable core-measured data that were not available to us. Thus, we conducted a series of diverse experiments to characterize pores and determine the flow properties of twelve Middle Bakken cores as representatives for Unconventional low-permeability reservoirs. The experiments included centrifuge, mercury intrusion capillary pressure (MICP), nitrogen adsorption, nuclear magnetic resonance (NMR), and resistivity. From the centrifuge measurements, we determined the mobile fluid saturation range for water-displacing-oil and gas- displacing-oil in addition to irreducible fluid saturations. From MICP, nitrogen adsorption, and NMR, we determined pore-size distribution. Finally, from resistivity measurements we determined tortuosity. In addition to flow characterization, these data provided key parameters that shed light on the mechanisms involved in primary production and enhanced oil recovery technique.
The cores were in three conditions: clean, preserved, and un-cleaned; the hydrocarbon included Bakken dead oil and decane; and the brine included Bakken produced water and synthetic brine. After saturating the cores with brine or oil, a set of drainage and imbibition experiments was performed. NMR measurements were conducted before and after each saturation-desaturation step. After cleaning, pore size distribution was determined for four cores using MICP and nitrogen adsorption tests. Finally, resistivity was measured for five of the brine-saturated cores.
The most significant results include: 1. Centrifuge capillary pressure in Bakken cores was on the order of hundreds of psi—both in positive and negative range. 2. Mobile oil saturation range for water-displacing-oil was very narrow (around12 % PV) and much wider (around 40 % PV) for gas-displacing-oil. 3. In Bakken cores, oil production by spontaneous imbibition of high-salinity brine was small unless low-salinity brine was used for spontaneous imbibition. 4. Resistivity measurements yielded unexpectedly large tortuosity values (12 to 19), indicating that molecules and bulk fluids have great difficulty to travel from one point to another in shale reservoirs.
Pressure Transient Analysis for a Unique Shale Gas Condensate Well, Actual Field Case
Authors: Ibrahim M. , Pieprzica C. , Vosburgh E. , Dabral A. , Olayinka O. , Larsen S. 
Published: October 2017

Abstract
Horizontal drilling accompanied with Hydraulic fracturing makes the unconventional reservoir a viable addition to worldwide production. Hydraulic fracturing of a well is the largest cost when evaluating total well expense. Therefore, understanding the fracture performance is fundamental to the success of a shale well. The two main factors controlling a shale horizontal wells performance is completion design and reservoir quality. The completion efficiency depends on factors such as well spacing, stage spacing, cluster spacing, fluid volume, proppant type and volume, injection rate, type of fracture fluid and gas price.
There are many techniques used to evaluate the hydraulic fracture performance. Some include post fracture analysis, tracer analysis, micro seismic analysis, rate transient analysis, production log analysis, fiber optics data and pressure transient analysis.
This paper presents the integration of completion data, petrophysical data, fluid sample analysis, mini-frac analysis, and flowback data in matching long term buildup data. More than 6 months of data was collected for one of the unique shale gas condensate wells during the appraisal stage of an area. The analysis showed the effect of liquid drop out and phase segregation in the flow regimes.
Also, this paper presents a different analytical model used to match the actual buildup data. The resulting model is used in building a reservoir model to forecast performance for the well.
Use of Experimental Design for Uncertainty Assessment in Deep Offshore Gulf of Mexico
Authors: Ait-Ettajer T. , Whiteley G. , Abrarova G. , Fontenla Alvarez S. , Dong Y. , Fajardo C. , Cendrowski R. , Giannangeli F. 
Published: October 2017

Abstract
The lower tertiary Wilcox trend, which extends from Alaminos Canyon(AC) to Keathley Canyon (KC), is attracting more attention from the oil&gas industry (Vassilellis, et al., 2013) and more production and final investment decision (FID) are expected in the near future according to WoodMac latest reports. The range of reserves of the lower tertiary Wilcox trend is between 3 and 15 billion barrels (Dusterhoft, Strobel, & Szatny, 2012). Buckskin field is among the fields located in this trend at approximately 290 miles south-east of Houston (Ait-Ettajer, 2017). The Buckskin discovery well (yacimiento_golfo_mexico.aspx, 2009) and the appraisal wells drilled afterwards, encountered more than 1,000 foot hydrocarbon column between 25,000 and 27,000 feet depth and 6000 feet of water, in sand bearing turbidite, located in different compartments bounded by a complex fault network. Despite, the subsurface studies performed following the drilling campaign, significant uncertainties remained. Several approaches were assessed in order to study the impact of those uncertainties on the hydrocarbon storage and mobility of this field. Probabilistic methods based on experimental design and Monte-Carlo simulations, were chosen in order to optimize the development plan and the reserves assessment, due to their robustness and their flexibility. Those probabilistic methods, combined with experimental design technique, allowed the identification of the key uncertainties and the definition of response model that predicts the range of oil in place and the optimization of the development plans, without the need to run hundreds of thousands realizations.
A New Comprehensive Numerical Model for Fracture Diagnosis with Distributed Temperature Sensing DTS
Authors: Sun He , Yu Wei , Sepehrnoori Kamy 
Published: October 2017

Abstract
The growing acceptance of Distributed Temperature Sensing (DTS) has been contributed by its accurate real-time estimation of the staged fracturing effectiveness. The objective of this study is to develop a new model to simulate fluid flow and temperature profiling of horizontal wellbores with complex fracture geometries. This study offers an enhanced estimation of key reservoir and fracture properties with DTS, which may throw light on the further optimization of the fracturing projects. Specifically, we developed a comprehensive numerical model to simulate flow and temperature field in unconventional reservoir with DTS. In our robust wellbore model, multiphase flow with slippage is simulated accurately. Flow and thermal models are fully coupled between wellbore and reservoir model. The new model was validated with exiting simulator of OLGA and CMG. After validation, we applied our model to simulate single fracture and five fractures cases with varying parameters. The impacts of several parameters, including reservoir matrix permeability, fracture conductivity, reservoir rock thermal conductivity, heat exchange coefficient, fracture spacing, and fracture geometry, on temperature profile along the wellbore were analyzed. Several practical conclusions have been drawn from the sensitivity analysis. Although numerous simulators have been developed to simulate the DTS data, relatively few existing models can handle the multiphase flow with slippage, heterogenous reservoir properties and fracture with complex geometries due to the complexity of the calculations and computational cost. Our model is more rigorous than the prior models to simulate the DTS data through the advanced wellbore and reservoir models.
Evaluation of Pressure-Transient Behavior of Unfractured Vertical, Vertically Fractured, and Horizontal Wells in a Composite Reservoir with an Active Aquifer and Moving Fluid Interfaces
Authors: Poe Bobby D. , Hender Donald G. 
Published: October 2017

Abstract
Pressure-transient models are presented for evaluation of the behavior of vertical, vertically fractured, and horizontal wells in radial and linear (three-region) composite reservoirs with moving fluid fronts. The Laplace Transform Finite Difference (LTFD) numerical solution methodology combined with the well- known Buckley-Leverett (BL) frontal-advance equation have been used to develop solutions for the moving boundary problem. Hybrid semi-analytic and numerical solutions have been constructed for finite-conductivity vertical fractures and infinite-conductivity horizontal wellbores. Complete descriptions of the mathematical models are presented; the pressure-transient solutions, frontal position and velocity, and saturation distributions. Indications are that monitoring of the transient behavior permits detection of water encroachment to the producing well, prior to breakthrough. This enables modifications in the production operations to be taken proactively to delay breakthrough.
The results of the pressure-transient models reported in this paper have been compared with the available moving boundary radial composite solutions in the literature and the results of the vertically fractured and horizontal well solutions have been validated using analytic and numerical reservoir simulation. Six well and reservoir model combinations have been considered in this investigation for which oilfield applications exist for each composite system considered. These include solutions of the pressure-transient behavior of an unfractured vertical well in a radial composite reservoir, a vertically fractured well in linear and radial composite systems, a horizontal well in radial and linear composite systems, and a vertical fracture intersected by a horizontal well in a linear composite system. Extension of the solution methodology used in this study for evaluating the pressure-transient behavior of a selectively completed horizontal wellbore in a cylindrical composite reservoir has also been considered in this study. Each of these solutions include moving fluid fronts, whose position and velocity are determined from the frontal advance model and fractional flow theory. General fractional flow solutions have been implemented that utilize conventional laboratory relative permeability measurements.
Deployment of a Remotely Activated Liner Hanger System to Improve Drilling and Well Construction Efficiencies
Authors: Munshi Ammar A. , O'Connor K. , McMahon S. , Carmody M. 
Published: October 2017

Abstract
Operators for deepwater and extended-reach wells, where daily rig costs can exceed $500k per day, are continuously exploring methods to reduce nonproductive time (NPT) and increase operational efficiency. For example, a common point of focus is liner string deployments in deepwater and highly deviated applications that predominantly employ hydraulic liner hangers.
This paper presents a new liner hanger system that uses simple mud flow signals to remotely communicate with a downhole controller on the work string. The controller receives the specific activation signal from the surface and then relays that signal to the liner hanger or running tool via an acoustic signal. The results of the first test trial of the remote liner hanger system controller will be discussed.
The traditional method for setting a hydraulic liner hanger includes the use of single or multiple activation balls being dropped from the surface so that pressure can be applied to the work string to function the hydraulic liner hanger and running tool. However, in deepwater and extended-reach applications, many operational issues experienced with running hydraulic liner hangers are related to not landing the ball on seat, which can lead to days of NPT. Developing a liner hanger system that does not rely on dropping activation balls from the surface nor rely on pipe manipulation can reduce the time required to run the liner hanger and minimize issues that lead to higher NPT.
This new system does not require dropping activation balls from the surface, reducing the amount of running tools in the work string and the amount of time required to set the liner hanger. The system also allows the use of a solid liner hanger body, eliminating the potential leak paths inherent to hydraulic liner hangers. The results will demonstrate the first deployment of the remote system controller in a well, confirming that it detects various remote commands from the surface. The results will also demonstrate how the system enables operators to choose the activation method depending on the well and rig conditions, for example, varying the flow rate activation signals. This system and method can improve well construction efficiencies and is a step in the direction of a smarter and safer oilfield through more automated operations.
A Novel Approach to Developing and Conditioning Part Field Models for a Complex Fluvio-Deltaic Reservoir: An Example from the Wara Formation in the Greater Burgan Field
Authors: Dashti L. , Filak J. M. , Bond D. J. , Banagale M. R. , Al-Houti R. A. , Luneau B. A. , Molinari D. 
Published: October 2017

Abstract
The Wara reservoir is one of the main producing formations of the giant Greater Burgan field. It has been on production under natural depletion for many years. A massive water-flood of this formation has recently commenced. This was preceded by a large-scale pilot water flood the aims of which included enhancing reservoir understanding. This paper describes how historical data, including data from the large-scale pilot, were used to construct representative part filed models.
The area of the pilot water flood has significant volumes of data, including core and log data and dynamic data such as pressure transient data, interference tests, tracer tests and cased-hole logs. These provide valuable information for reservoir characterization.
The Wara formation was deposited in a tidally influenced fluvio-deltaic environment where sand continuity is complex. There was a desire to develop realistic geological and simulation models that accounted for our understanding of Wara geology and were consistent with the large volumes of surveillance data.
A major challenge was the choice of an appropriate area for the part field model. This was chosen so as to allow water influx into the area of interest over the life of the field to be accounted for and to allow relatively simple boundary conditions to be applied.
Geological models were constructed using object based techniques. These models used reservoir rock types that were developed to broadly match permeability-height estimates from pressure transient data.
The geological models were not guaranteed to account for the sand connectivity inferred form the surveillance data. A streamline based screening technique was used to exclude models that did not broadly capture the interpreted connectivity.
Dynamic simulation models were then developed and conditioned to data using conventional assisted history matching techniques. At this stage, some sensitivities related to boundary conditions were explored. Sand connectivity was not varied at this stage.
Some examples are given as to how the resulting conditioned models have been used to address questions about expected future reservoir performance. Specifically questions related to proposed well spacing and pattern type are discussed.
This paper describes a novel approach to developing models that are geologically realistic and are consistent with the interpretation of reservoir connectivity from a range of surveillance data. This involves using a streamline based screening tool before using assisted history matching techniques. Such an approach can be applied to both part and full field models.
The challenges of using such an approach with part field models are described. Some guidance is given to know when it would be appropriate to try to develop and condition part field models.
New Multisensor Inversion Technology for Imaging Near-Wellbore Petrophysical Properties from Resistivity, Sonic, and Density Data
Authors: Shetty Sushil , Liang Lin , Simoes Vanessa , Canesin Fabio , Boyd Austin , Zeroug Smaine , Sinha Bikash , Habashy Tarek , Domingues Ana Beatriz , Amorim Claudia , Abbots Frances 
Published: October 2017

Abstract
We present an automatic inversion method for data acquired in a vertical well by the sonic, induction, and density borehole logging tools. The method is designed for oil-bearing or gas-bearing formations drilled with oil-base mud. The inversion accounts for challenging scenarios where the tool sensors are affected by filtrate invasion, gas phase, complex mineralogy and mechanical damage. The output consists of porosity and radial distributions of fluid saturations and pore shape extending several feet from the wellbore. The output is robust, accurate, and consistent with radial investigation depths of all the tools.
The formation model assumed in the inversion has homogeneous porosity and radially varying pore shape, oil, gas, and water saturation. Radial changes in fluid saturation and pore shape are caused by filtrate invasion and mechanical damage respectively. The data for different tools are simulated from sonic and electromagnetic forward solvers, linked to the formation model through a saturation-resistivity transform and an effective medium rock physics model. The inversion estimates formation properties such that the simulated data match the measured data. For the first time, sonic data for both dipole flexural wave and monopole compressional-headwave are included. These data are sensitive to porosity and pore shape effects, and the compressional-headwave additionally provides sensitivity to gas saturation in soft formations.
The inversion was tested on synthetic data and applied to two field data sets for gas-bearing formations. The results are visualized as 2D images with radial distribution of formation properties at each log depth. The images characterize radial depth of filtrate invasion and mechanical damage, which can guide completion and production decisions. The inversion also provides far-field saturation and porosity. The far-field properties are in overall good agreement with core data and traditional interpretation, with differences from traditional interpretation in key intervals. Quality controls enable checking validity of models assumed in the inversion. The results demonstrate an efficient inversion framework for guiding formation evaluation decisions in challenging scenarios.
Towards a Complete Removal of Barite Weighted Water and Oil Based-Drilling Fluids in Single Stage
Authors: Mahmoud Mohamed , Elkatatny Salaheldin 
Published: October 2017

Abstract
Barite is one of the most common weighting materials used in drilling fluid for deep oil and gas wells. Consequently, the main source of solids building the filter cake is the weighting material used in drilling fluids ‘Barite particles’. Barite is insoluble in water and acids such as HCl, formic, citric, and acetic acids, as well as the barite has low solubility in chelating agent such as Ethylene Diamine Tetra Acetic Acid (EDTA).
The present study introduces a new formulation to dissolve the barite filter cake using converters and catalysts. Barite can be converted to barium carbonate at high pH medium using combination of potassium hydroxide (KOH) and potassium carbonate (K2CO3) solution. Then HCl acid can be used to dissolve the barium carbonate. Another solution is to use high pH EDTA chelating agent and potassium carbonate as a catalyst/converter in one step. The removal formulation also contains polymer breaker (oxidizers). The three components of the new formulation are compatible and stable up to 300°F. Solubility tests were conducted using industrial barite particles with size ranged from 30 to 60 micron. The solubility experiments were carried at 300°F for 24 hours. Different concentrations of catalyst were added to select the optimum concentration. The designed formulation was examined to remove filter cake formed by Barite drilling fluid using High Pressure High Temperature cell (HPHT).
The result of this study showed that the barite removal efficiency of new formulation reached to 87 % in water base mud and 83 % in oil base mud. The solubility test results presented that the solubility of barite particles in 0.6M EDTA was 62 % in 24 hours at 300°F. Adding potassium carbonate catalyst to the 0.6M EDTA solution the increased the solubility of barite to 90 wt. % in 24 hours. The use of converting agents increased the barite solubility from62% to 90% in EDTA. The EDTA was compatible with the polymer breaker (oxidizer) so the filter cake removal will be in single stage. The oxidizer concentration used was 10 wt%, potassium carbonate concentration was 10 wt% and EDTA concentration was 0.6M. The new formulation achieved 85% filter cake removal in both oil-based and water-based drilling fluids. In oil base mud a water wetting surfactant, mutual solvent, and emulsifier should be added to the formulation to remove the oil. In this study, two solutions were proposed to remove the barite filter cake and barite scale from oil and gas wells at different conditions. The first one is by using HCl acid after converting the barium sulfate to barium carbonate using high pH medium such as KOH and K2CO3. Then HCl can easily remove the barium carbonate. The second method is to create the high pH medium by using the removal fluid itself which is EDTA chelating agent in addition to potassium carbonate as converter.