bluuebunny/crossref_metadata_2025_split huggingface dataset:
3D Structural Modeling and Property Characterization for Optimized Completion Design in the Wolfcamp Formation, Delaware Basin
Authors: Azike O. , Ajisafe F. , Pope T. , Burkhardt C. , Helmreich A. , Phelps M. 
Published: June 2014

Abstract
For a well in the Permian Basin, openhole (OH) triple combo logs from five nearby offset wells and gamma ray from a horizontal well were used to deduce a workflow to define the 3D structural geometry of the drilled horizontal section. After establishing the structural architecture of the drilled lateral section to determine which part of the lateral is in or out of zone, lithology and petrophysical properties from the offset wells were propagated using geostatistical algorithms to match the horizontal well path. A relatively distant offset well with an advanced log suite was also utilized to generate synthetic mechanical rock properties along the lateral. These data were used for optimized completion design by placing stimulation stages in similar rock and intelligently placing perforation clusters. Placement was guided by rock type and geomechanical properties as opposed to geometrical spacing along the lateral.
The assumption that rock properties are homogenous and structural dip is fairly constant in horizontal drilling has been proven to be untrue in recent studies, and production logs have shown that not all stages/perforation clusters contribute to production. The consequence of not using image log measurements in geosteering the lateral to ensure that the lateral is in the target reservoir can lead to ineffective stimulation treatment and possibly skipping stages in parts of the lateral that is landed in a higher stress rock.
The successful application of the workflow enabled us to determine the structural geometry along the drilled horizontal well and also build a 3D structural and property model, which was successfully used for the optimized stimulation staging and completion design. This produced a more successful stimulation treatment with approximately 67% more sand placed per stage compared to an offset well drilled in the same target zone.
Wellbore Monitoring in Unconventional Reservoirs: Value of Accurate DTS Interpretation and Risks Involved
Authors: Kalia Nitika , Gorgi Sam , Holley Eric , Cullick A. S. , Jones Tim 
Published: June 2014

Abstract
Wellbore monitoring techniques are proving to be significant in reservoir management and intervention design, particularly in unconventional fields where fluid flow behavior is not very well understood. Distributed temperature sensing (DTS) technology allows for an estimation of zonal flow rates in the entire well as a function of time during hydraulic fracturing, as well as during the production phase.
In this work, a novel transient thermo-hydraulic model that includes fluid transport and thermal coupling and simulates fluid flow and temperature in both the wellbore and reservoir is presented. Real DTS data from a hydraulic fracturing operation in a low-permeability basin in west Texas has been inverted using this model. Flow allocation based on the thermo-hydraulic model is presented. It was found that the reservoir heterogeneity, and hence the zonal flow rates, can be accurately obtained based on temperature and pressure data from the well.
Most of the steady-state DTS data inversion models are typically applicable to production scenarios, where the transient in temperature has vanished. Injection operations, such as in fracturing where the temperature does not achieve a steady- state during the injection stage, require a transient model that can capture the initial-time effects. Also, some of these models fail to include the Joule-Thomson effect, and this leads to an incorrect flow allocation. The thermo-hydraulic model developed in this work includes both the Joule-Thomson and transient effects. It can be applied to non-reactive fluid injection during stimulation operations, such as matrix acidizing and fracturing. In particular, application of the model for fluid distribution before, during, and post-fracturing provides an estimate of the efficiency of fracturing stages.
The Effect of Osmotic Pressure on Improve Oil Recovery from Fractured Shale Formations
Authors: Fakcharoenphol Perapon , Kurtoglu Basak , Kazemi Hossein , Charoenwongsa Sarinya , Wu Yu-Shu 
Published: June 2014

Abstract
Shale swelling during drilling is attributed to osmotic pressure, where low-salinity water enters the shale pores to cause swelling. Low-salinity water injected into high-salinity Bakken formation could similarly enter the matrix pores to displace oil by counter-current flow observed in core experiments. As a result, we believe, low-salinity water can potentially enhance oil recovery from oil-wet Bakken formation.
In this paper, we report experimental and numerical modeling studies we conducted to evaluate the potential of low- salinity waterflooding in Bakken. For laboratory experiments, we used horizontal core plugs drilled parallel to the bedding plane.
The mathematical included osmotic pressure, gravity and capillary effects. In the mathematical model, the osmotic pressure mass transfer equations were calibrated by matching time-dependent salinities in a published laboratory osmotic pressure experiment. We also modeled oil recovery for a Bakken core using our osmotic pressure mass transport model. The results indicate that osmotic pressure promotes counter-current flow of oil from both the water-wet and oil-wet segments of the core.
Experimental Investigation of Enhanced Recovery in Unconventional Liquid Reservoirs using CO2: A Look Ahead to the Future of Unconventional EOR
Authors: Tovar Francisco D. , Eide Øyvind , Graue Arne , Schechter David S. 
Published: June 2014

Abstract
The poor rock quality and matrix permeability several orders of magnitude lower than conventional oil reservoirs observed in unconventional liquid reservoirs (ULR) presents many uncertainties on the storage capacity of the rock and the possibility of enhancing recovery. The technological advances in multiple stage hydraulic fracturing and horizontal drilling have improved the overall profitability of oil shale plays by enhancing the matrix – wellbore connectivity. The combination of these technologies has become the key factor for the operators to reach economically attractive production rates in the exploitation of ULR, causing a lot of focus on their improvement. However, as the reservoir matures, primary production mechanisms no longer drive oil to the hydraulic fractures, making the improvement of matrix – wellbore connectivity insufficient to provide economically attractive production rates. Therefore, the need to develop enhanced recovery techniques in order to improve the displacement of the oil from the matrix, maintain profitable production rates, extend the life of the assets and increase ultimate oil recovery becomes evident.
This study presents experimental results on the use of CO2 as an enhanced oil recovery (EOR) agent in preserved, rotary sidewall reservoir core samples with negligible permeability. To simulate the presence of hydraulic fractures, the ULR cores were surrounded by high permeability glass beads and packed in a core holder. The high permeability media was then saturated with CO2 at constant pressure and temperature during the experiment. Production was monitored and the experiment was imaged using x-ray computed tomography to track saturation changes inside the core samples.
The results of this investigation support CO2 as a promising EOR agent for ULR. Oil recovery was estimated to be between 18 to 55% of OOIP. We provide a detailed description of the experimental set up and procedures. The analysis of the x-ray computed tomography images revealed saturation changes within the ULR core as a result of CO2 injection. A discussion about the mechanisms is presented, including diffusion and reduction in capillary forces. This paper opens a door to the investigation of CO2 enhanced oil recovery in ULR.
Zonal Isolation Technology Enables Production without Post-Frac Intervention
Authors: Allen R. , Oberg L. 
Published: June 2014

Abstract
Hydraulic fracturing in unconventional reservoirs has increased rapidly in the past ten years. Each year, technologies are improved and methodologies are refined, making this process faster, safer, and more economical.
Currently, plug-and-perforate is the most common type of hydraulic fracturing diversion method. During this type of operation, composite plugs are spaced into a wellbore to divert the hydraulic fracturing treatment to a specific zone in the reservoir. After each wellbore has been thoroughly fractured, coiled tubing or threaded pipe, in tandem with positive displacement motors, is summoned to remove the composite plugs from the wellbore to enable production.
This paper will describe a new zonal isolation technology that will provide operators with a number of benefits that improve operational efficiency and enable earlier production. The benefits from this technology include eliminating the necessity for composite plug removal after the conclusion of all zonal stimulations, and a far larger than traditional ID through which high-rate flowback and production can be accommodated. An integral aspect of this technology is the use of disintegrating fracturing balls that rapidly deteriorate after stimulation. By eliminating composite plug removal, operators will spend fewer days on location, reducing HS+E risks. Operators can also complete longer lateral wellbores more quickly and economically. In general, operators will also realize reduced total zonal completion cost and achieve quicker production when compared to traditional plug-and-perf completion methods. Finally, this new zonal isolation technology may enable future intervention for re-stimulation operations, if required.
As exploitation of unconventional reservoirs grows globally, this technology will give operators more flexibility in designing completions, particularly in remote locations.
Effect of Dissolved Iron and Oxygen on Stability of HPAM Polymers
Authors: Seright R. S. , Skjevrak Ingun 
Published: June 2014

Abstract
This paper describes an experimental study of the stability of an HPAM polymer and an HPAM-ATBS terpolymer in the presence of varying initial levels of dissolved oxygen (0 to 8000 parts per billion, ppb), Fe2+ (0 to 220 parts per million, ppm), and Fe3+ (0 to 172 ppm). A special method was developed to attain and confirm dissolved oxygen levels. Stability studies were performed at 23°C and 90°C. For Fe2+ concentrations between 0 and 30 ppm, viscosity losses were insignificant after one week so long as the initial dissolved oxygen concentration was 200 ppb or less. Above this level, significant viscosity losses were seen, especially if iron was present.
If the temperature is high, a greater need arises to strive for very low dissolved oxygen content. For samples stored for one week at 90°C with only 10-ppb initial dissolved oxygen, contact with steel caused HPAM-AMPS solution viscosity losses greater than 30%. In contrast at 23°C, contact with steel caused no significant degradation so long as the dissolved O2 concentration was 1000 ppb or less. Several different methods are discussed to control oxidative degradation of polymers during field applications. We advocate physical means of excluding oxygen (e.g., stopping leaks, better design of fluid transfer, gas-blanketing, gas-stripping) over chemical means.
Addition of Fe3+ to polymer solutions caused immediate crosslinking. Since crosslinked polymers were never observed during our studies with Fe2+, we conclude that free Fe3+ was not generated in sufficient quantities to form a visible gel.
Modeling Development of a Thermal Gas-Oil Gravity Drainage Process in an Extra-Heavy Oil Fractured Reservoir
Authors: Niz-Velásquez E. , Bagheri S. R. , van Dorp J. J. , Jennings J. 
Published: June 2014

Abstract
Thermal Gas-Oil Gravity Drainage (T-GOGD) is an attractive Enhanced Oil Recovery (EOR) method applicable to naturally-fractured reservoirs (NFR). The process is successfully applied in Qarn Alam, a heavy oil field in Oman. This paper presents a dynamic modeling optimization and uncertainty analysis workflow for T-GOGD in a bitumen-bearing fractured reservoir based on realistic 3D fracture characterization.
In T-GOGD, the fractures are displaced to steam to provide a (matrix) gravity drainage potential while heating the reservoir at the same time. One of the recovery mechanisms associated with T-GOGD is thermal expansion, which can result in high initial rates, but may cause plugging of the fracture system in the case of extra-heavy oil (bitumen) if the expanded oil cools down before it is being produced. This situation requires short-distance well configurations and/or steam stimulation cycles to establish communication. In a NFR, steam vapour occupies the fracture system while oil drains through the matrix, increasing the area for heat transfer with respect to the steam chamber case; the process therefore differs significantly from SAGD and a different production function applies.
Shell's in-house reservoir simulator MoReS with advanced dual-permeability capability, is used to model development of T-GOGD in a bitumen reservoir employing 3D element-of-symmetry models. A realistic fracture characterization and modeling process is described. The geometrical well configuration and operating schedule and strategy are optimized on an economic function for a deterministic subsurface realization. Using an uncertainty analysis workflow, cumulative distribution functions of recovery and steam-oil ratio are generated. Finally, robust optimization is explored using an economic objective function. The study concludes that 1) relatively large well spacing is feasible while injector-producer horizontal well offset is necessary to avoid steam channeling to the producer well, 2) live steam production control is a robust operating strategy, 3) performance is most sensitive to matrix permeability and oil viscosity, and 4) vertical fracture connectivity plays an important role on the process performance. T-GOGD has significant potential to develop bitumen resource in naturally fractured carbonates.
Field Testing the Polysaccharide Schizophyllan: Results of the First Year
Authors: Leonhardt Bernd , Ernst Burkhard , Reimann Sabrina , Steigerwald Alexander , Lehr Florian 
Published: June 2014

Abstract
For the first time ever a novel biopolymer is being field tested in a mature onshore oil field in Northern Germany. This biopolymer – named Schizophyllan after its producing fungus – shows excellent viscosifying efficiency and high tolerance towards harsh reservoir conditions such as high temperature, salinity and shear. Hence, this biopolymer allows for application in reservoirs that could so far not be polymer flooded and extends the operating envelope for polymer flooding to temperatures up to 275°F at arbitrary salt contents. Furthermore, it provides an environmentally friendly alternative to the commonly used synthetic polymers.
To run this first field test petroleum engineers of Wintershall Holding GmbH, chemical research scientists and biotechnologists of BASF SE are closely cooperating in an integrated team. An existing biotechnological plant at the BASF compound in Ludwigshafen, Germany, was partly reconstructed into a production facility for providing sufficient biopolymer for the field pilot. In the oil field itself an existing production site was extended into an operation site also hosting the surface facilities for treatment of the produced water used for re-injection and preparation of the injected biopolymer solution.
Being trucked to site as mother solution the Schizophyllan is mixed on-the fly with the treated, high-salinity reservoir brine and injected into a newly drilled injector in the project area surrounded by three production wells. A comprehensive surveillance program was set up comprising regular microbiological sampling, pressure monitoring using permanent down-hole gauges as well as frequent analyses and production tests to monitor the progress of the polymer trial.
The paper presents further information on the biopolymer Schizophyllan, describes the preparation and the setup of the field trial and summarizes results and experiences from the first year of the two-year field trial.
Imbibition Characteristics of Marcellus Shale Formation
Authors: Morsy Samiha , Gomma A. , Sheng J. J. 
Published: June 2014

Abstract
In order to understand the effect of injected stimulation fluids on nano-darcy permeability, naturally fractured shale reservoirs, an integrated study of spontaneous imbibition was performed. In this study, oil recovery during spontaneous imbibition in naturally fractured shale samples was investigated using different water formulations. Different water solutions were formulated by adding different amounts of HCl and NaOH to either distilled water or 2 wt% KCl-base brine solution. Eight water formulations, distilled water, 2% KCl brine, low pH HCl solutions (0.74-1.2), and high pH alkaline solutions (11.78-12.4) were examined to recover oil from shale rocks. Outcrop samples from Marcellus shale formation were used in this study. The samples were 2.54 to 3.81 cm in diameter and 0.762 to 5.08 cm in length. Firstly, we studied the average porosity of the used samples using CT Scanning. The average porosity was around 6%. Secondly, we studied the rock stability and spontaneous imbibtion of the different Marcellus samples in distilled water, 2 wt% KCl, low pH solutions (0.741.2), and high pH alkaline solutions (11.78-12.43). During the spontaneous imbibition, the maximum oil recovery was 4% using low pH solution of pH0.74 (3 wt% HCl in 2 wt% KCl base brine solution) or high pH solutions (pH11.9 and pH12.4). There was no difference between the oil recoveries achieved by distilled or 2 wt% KCl solution which might indicate that Marcellus shale is not sensitive to salinity. Oil recoveries from Marcellus shale slightly improved when using low or high pH solutions due to wettability alteration that has been supported by the changes in the measured contact angles before and after exposure to such solutions. The rock hardness of Marcellus samples was significantly affected by using both high and low pH solutions, which resulted in 55-94% loss of its initial value using low pH solutions and 50-68% when using high pH solutions.
Adsorption of a Switchable Cationic Surfactant on Natural Carbonate Minerals
Authors: Cui Leyu , Ma Kun , Abdala Ahmed A. , Lu Lucas J. , Tanakov Ivan , Biswal Sibani L. , Hirasaki George J. 
Published: June 2014

Abstract
A switchable cationic surfactant, e.g., tertiary amine surfactant Ethomeen C12, has been previously described as a surfactant that can be injected in high pressure CO2 for foam mobility control. C12 can dissolve in high pressure CO2 as a nonionic surfactant and equilibrate with brine as a cationic surfactant. Here we describe the adsorption characteristics of this surfactant in carbonate formation materials. The adsorption of this surfactant is sensitive to the equilibrium pH, the electrolyte composition of the brine, and the minerals in carbonate formation materials.
Pure C12 is a nonionic surfactant. When it is mixed with brine, the solution has high pH and limited solubility. However, when the surfactant solution in brine is equilibrated with high pressure CO2, the pH is about 4, the surfactant switches to a cationic surfactant and becomes soluble. Thus the adsorption is also a function of pH. The adsorption of C12 on calcite at low pH is low, e.g., 0.5 mg/m2. However, if the carbonate formation contains silica or clays, the adsorption is high, as is typical for cationic surfactants. The adsorption of C12 on silica decreases with increase in divalent (Ca2+ and Mg2+) and trivalent (Al3+) cations. This is due to the competition for the negatively charged silica sites between the multivalent cations and the monovalent cationic surfactant. An additional effect of the presence of divalent cations in the brine is that it reduces the dissolution of calcite or dolomite in presence of high-pressure CO2. The dissolution of calcite and dolomite is harmful because of formation damage and increased alkalinity. The latter raises the pH and thus increases adsorption of C12 or even cause surfactant precipitation.
Simulation of Polymer Injection under Fracturing Conditions - A Field Pilot in the Matzen Field, Austria
Authors: Zechner Markus , Clemens Torsten , Suri Ajay , Sharma Mukul M. 
Published: June 2014

Abstract
Polymer flooding leads to enhanced oil recovery by accelerating oil production and improving sweep efficiency. However, owing to the higher viscosity, injectivity of polymer solutions is of some concern and is important to understand to predict incremental oil recoveries. Achieving high polymer injection rates is required to increase oil production rates.
In the field test performed in the Matzen field (Austria), polyacrylamide polymers have been injected for the past two years. Core flood experiments with these polymers showed a significant increase in apparent viscosity due to the viscoelastic properties of the polymer solutions. Also, severe degradation of the polymer solution at high flow velocities was detected. In addition to core flood experiments, flow experiments through fractures were performed. In these experiments, shear-thinning and limited degradation of the polymer solution was observed and quantified.
Detailed polymer injection simulations were conducted that included complex polymer rheology in the fractures and the matrix. The reservoir stress changes and its effects on the fractures were also taken into account due to cold polymer injection. The results of the simulations matched the field data both for water floods and polymer test floods.
The simulations revealed two distinct phases during injection of the polyacrylamide polymer solutioninjection under matrix conditions in an early phase resulting in severe degradation of the polymers andinjection under fracturing conditions once the formation parting pressure is reached, leading to limited degradation of the polymers.
The calibrated model was used to investigate the impact of polymer rheology and particle plugging on injectivity and fracture growth.
The results of the field test and the simulations indicate that screening of fields for polyacrylamide polymer projects need to include geomechanical properties of the reservoir sand and cap/base rock in addition to the conventional parameters used in the simulations such as oil viscosity, water salinity, reservoir temperature and reservoir permeability. Furthermore, it is shown that water quality is crucial for polymer EOR operations.