bluuebunny/crossref_metadata_2025_split huggingface dataset:
Indentaion Hardness for Improved Proppant Embedment Prediction in Shale Formations
Authors: Mueller Martin , Amro Mohammed 
Published: May 2015

Abstract
The aim of hydraulic fracturing is the generation and maintenance of highly permeable pathways. To achieve this, a high hydraulic pressure is applied to overcome the breakdown pressure in developed formations. To avoid the closure of the generated fractures due to the acting in-situ stress in the subsurface, proppantsareused. The hydraulic conductivity (Cf) of such a fracture is defined as the permeability of the proppant pack (kpr) times the fracture width (wf). However, this value cannot be considered a constant. The increasing effective pressure leads to an increased stress on the proppants, thus increasing their embedment into the formation surface. Such a situation becomes particularly critical in weak formations and in formations where the interaction between the frac fluid and the formation can lead to a change in the mechanical properties in the fracture face. This paper will present an approach to model the embedment of various kinds of proppant packs with respect to the proppant size distribution and the proppant density. This approach uses the indentation hardness of the surface formation to calculate the embedment. The advantage of this parameter, which can be measured by applying the hardness test according to Brinell, is that it describes the mechanical properties of the surface of the formation. This area, which is highly influenced by the treatment fluid, can show great differences in the mechanical behavior compared to the untreated area. This can lead to an under- or overestimation of the embedment, since the mechanical parameters normally used for calculation are measured on core samples representing the mechanical behaviour of the untreated rock mass. The consideration of the indentation hardness can lead to a more accurate embedment prediction, since it describes the behaviour of the first 0.1-2 mm of a surface, in which the embedment alone can lead to a closure of a fracture. The first series of hardness tests according to Brinell, conducted on different shale types, have proven that the fluid composition affects the indentation hardness of the samples, which will of course affect the depth of the embedment. The measurements are the basis for the embedment modelling which will be presented in this article.
Pressure Behavior and Fracture Development During Polymer Injection in a Heavy Oil Saturated Unconsolidated Sand
Authors: Zitha P. L. , Barnhoorn A. , Logister R. 
Published: May 2015

Abstract
Polymer injection into unconsolidated sand-packs saturated with either brine or model medium-heavy oil was investigated using a bore-hole simulator (BHS). The high-pressure vessel of this apparatus enables fluid injection under radial or spherical flow regimes into porous specimens having diameter 40 cm and height up to 60 cm and at typical reservoir axial and radial stresses, i.e. up to 40 and 60 MPa respectively. We found that injectivity into heavy oil saturated sand-pack drops steeply to a minimum and then increases again rapidly before leveling off to a plateau. This behavior is in stark contrast with water or polymer injection into water saturated sand-packs, where constant injectivity is established after a rather short transient increase. The behavior of polymer injection into the oil saturated sand-pack strongly supports the idea of the stimulation of the near-wellbore area even though post-mortem visual observations of the porous sample it did not reveal open hydraulic fractures.
From Computerized Tomography to CFD: Production Flow Prediction in Realistic Perforation Tunnels
Authors: Satti Rajani , Kim Dong , Ji Minsuk , Bale Derek 
Published: May 2015

Abstract
Perforated completions have become a standard process of well completions, where the wellbore is connected to the reservoir by perforating the casing/cement wall and the formation to provide flow paths through which formation fluids can enter the wellbore. This flow path (defined by the perforation tunnel) is usually encompassed by drilling damage, crushed and the native formation zones, which influence the ability of the tunnel to flow hydrocarbons into the wellbore. Most numerical models assume the tunnel to be uniformly cylindrical in shape due to limited information available from downhole conditions as well as complexity involved in modeling detailed geometries. Such an assumption leads to discrepancies between computed and true flow efficiency and productivity of the tunnel.
In this paper, our objective is to develop a novel production flow model combining the capabilities of a perforation flow laboratory, computerized tomography (CT scan) and Computational Fluid Dynamics (CFD). As a first step, the complex geometry of the perforation tunnel (from a typical API RP-19B Section IV experiment) is obtained using a CT-scan. Next, the CT scan images are transformed using image processing software to generate a CAD model. The CAD model is then translated to a CFD model, where the conservation equations of mass, momentum and energy are solved to conduct a full-scale three-dimensional flow simulation around the tunnel. The fluid flow simulations provide details on the fluid velocities, pressures, skin factors and most importantly, the productivity ratio. Additionally, we have developed an analytical model that is aimed towards complementing the CFD model by computing the static/dynamic underbalance effects in conjunction with the tunnel's inflow characteristics.
The computational approach presented in this study is a first step towards leveraging digital rock physics to characterize the efficiency of a perforated completion. The study provides understanding into the steady/transient flow dynamics around realistic perforation tunnel geometries along with providing the framework for a completion engineer to better understand the design and optimization of a perforating job. Subsequently, it provides insight into devising the overall completion strategy for enhanced reservoir productivity.
Long Interval Foamed Diversion Treatment: A Mid-Scale Multizone Diversion Treatment Study
Authors: Parton C. , Singh D. , Khamatnurova T. , Lewis C. , Vo L. K. 
Published: May 2015

Abstract
Effective and uniform placement of treatment fluid across multiple zones can be challenging. This is particularly true during stimulation or remedial treatments for formation sand control, as well as during water shutoff treatments. Such challenges can be greatly enhanced when a long interval sand formation is largely heterogeneous. Good diversion technology is often what dictates treatment success. Current laboratory methods used to study diversion at downhole conditions can leave a large gap between laboratory and actual operational results. A recent midscale laboratory study involving a new complex multizone formation testing system has helped provide a method for closely simulating downhole conditions.
This paper describes a new laboratory testing setup, which allows an effective dynamic study of diversion. The new testing apparatus allows for evaluation of different critical parameters, such as concentration, temperature, and pressure on the diversion mechanism. Results are presented for laboratory case studies of diversion during different scenarios, including formation sand/fines control treatment and water shutoff treatment. The results generated can provide insight to help bridge the gap between a laboratory study and operations encountering multiple zones.
A Method for Determination of Near-wellbore Zone Properties Alteration during Well Drilling, Completion and Cleanup Operations by Combination of Numerical Simulations and Special Experimental Technique
Authors: Mikhailov D. , Ryzhikov N. , Makarova A. , Shako V. , Burukhin A. , Theuveny B. 
Published: May 2015

Abstract
Near-wellbore properties can be modified by invaded components of drilling muds or other technological fluids during drilling, completion, and workover operations. At different penetration depths, mud-component invasion creates multizone structures in the vicinity of the wellbore. These structures include external mudcake (mud solid components deposited at the sandface), internal mudcake (which is formed by mud components invaded into the reservoir formation), and mud-filtrate invaded zones. We suggest a model which is able to reproduce the dynamics of near-wellbore zone properties due to the invasion and removal of mud components. The model includes external mud cake buildup and lift-off processes, dynamics of internal mud cake, invasion of the mud filtrate. A new technique is suggested for estimating empirical parameters of both external and internal mudcakes by combining laboratory mud filtration experiments with core samples and a profile of invaded mud components reconstructed by X-ray microCT, image processing of a cleaved sample, and ultrasonic wave scanning.
Examples of reconstructed profiles of invaded mud components (solid particles and bentonite clay) as well as the procedure of determining internal mudcake parameters are discussed. A sensitivity study of the characteristics of mud invasion and early production stage is carried out to the properties of reservoir, external and internal mud cake and perforation length. The effects of fines migration and wettability alterations on dynamics of early production stage are simulated. It is shown that modification of properties of near-wellbore zone can significantly increase the final skin-factor and even kill the productivity of some formation layers that is especially applicable to the open-hole completion.
Investigation of Formation Damage By Deep Eutectic Solvents As A New EOR Agents
Authors: Mohsenzadeh A. , Al-Wahaibi Y. , Al-Hajri R. , Jibril B. , Joshi S. , Pracejus B. 
Published: May 2015

Abstract
Chemical injection into oil reservoirs is considered as an effective enhanced oil recovery (EOR) method. Although some of the chemicals improve oil recovery, they may have side effects on reservoirs such as formation damage due to fluids incompatibility or chemical interactions with reservoir rocks and fluids. Since our previous work indicated promising results from Deep Eutectic Solvents (DESs; DES1 - choline chloride:glycerol = 1:2 and DES2 - choline chloride:urea = 1:2) on enhanced heavy oil recovery, we now examine the possible effects of these DESs on sandstone formation damage.
Core flooding tests were performed at reservoir pressure and different temperatures to measure possible permeability changes by DESs injection. To understand the mechanisms of formation damage, different measurements were performed: Critical injection rate beyond which fines migration will take place, water shock effects on formation damage, dry core weight measurements before and after each core flooding tests, scanning electron microscopy (SEM), X-ray diffraction (XRD), and computed tomography (CT) scanning studies of fresh and treated core samples.
Permeability measurements by core flooding tests showed that the water shock phenomenon caused severe damage (65% reduction in absolute permeability) when distilled water was injected after brine flooding. Both DESs showed positive effect on reducing the water shock damages at different temperatures, where DES2 was much more effective when compared with DES1. Core weight measurements confirmed that whenever permeability damages were higher, the amount of core weight increase was also high. Moreover, results of SEM and quantitative XRD showed that precipitation and deposition inside pores are the main sources of formation damage. In addition, CT-scanning images provided good comparisons between fresh and damaged cores. We observed that using DESs showed that despite the DES's solutions role in preventing severe water shock damage and stabilizing the clays, there was still some formation damage caused by re-crystallization and precipitation processes reducing the permeability of the core samples.
Nearly Perfect Proppant Transport by Particle Fracturing Fluids Yields Exciting Opportunities in Well Completion Applications
Authors: Zhou Jia , Carman Paul , Sun Hong , Wheeler Richard , Brannon Harold , Gupta D. V. 
Published: May 2015

Abstract
Reservoir completion techniques, such as hydraulic fracturing for low permeability wells and frac pack for unconsolidated formation treatments, are normally applied to increase well productivity. The production of treated wells can be greatly enhanced by increased propped fracture area and proppant pack conductivity, both of which are highly dependent on proppant distribution in the fracture. Stimulation fluids with high viscosity are traditionally employed to open fractures and carry proppant into created fracture area in the formation. Although conventional crosslinked fluids are observed to provide good proppant suspension in laboratory environments, they might not provide the desired proppant transport under downhole conditions. Crosslinked fluids can be difficult to clean up, due to residual gel damage to proppant pack and formation. Post-treatment production analyses with crosslinked gel often indicate that the treatment did not achieve the designed conductive fracture area, which could be attributed to non-ideal proppant placement and/or significantly damaged fracture conductivity.
Perfect proppant suspension and transportation under downhole conditions is the ultimate dream for any fracturing fluid technology as it suggests proppant placement throughout the created fracture area to maximize stimulation efficiency of the treatment. Unlike conventional fracturing fluid technology which uses fluid rheology, polymer chains overlap and inter-chain crosslinking to generate viscosity, as the way to suspend proppant. The new concept involves a novel approach of particle packing mechanism to provide the near perfect proppant suspension in the new fluid, while maintaining minimum formation and proppant pack damage after breaking with frac fluid breakers. As to proppant transport mechanics with conventional fluids, viscosity and velocity above threshold levels can move proppant in a generally horizontal direction until gravity prevails as the velocity decays. However, neither viscosity nor velocity can overcome gravity to effectively move proppant upwardly from the wellbore. The packing mechanics of the soft particle fluids substantially mitigate the effects of gravity until such time as fracture closure confines the proppant.
This paper discusses laboratory results for this unique particle fluid system (1) to enhance proppant carrying capacity, (2) to deliver significantly better proppant vertical distribution of the fracture, (3) and to yield near 100% regained proppant pack conductivity. The system can unlock reservoir potential in areas requiring high propped fracture area and high regained conductivity, such as unconventional liquid-rich and offshore unconsolidated formations.
Study of Filtrate and Mud Cake Characterization in HPHT: Implications for Formation Damage Control
Authors: Salehi Saeed , Ghalambor Ali , Saleh Fatemeh K. , Jabbari Hadi , Hussmann Stefanie 
Published: May 2015

Abstract
Filtration from drilling fluids is a time-dependent and complex process. Mud composition, formation pressure, and temperature and permeability are some of the key factors affecting filtration behavior. Formation damage control and wellbore stability are the critical issues dealing with drilling fluid's filtration. The effects of mud cake build up and filtration with time aids the understanding the physical mechanisms. The increase of drilling in high temperature and pressure zones (HTHP) necessitates studies that can predict filtrate invasion, and particle bridging. Decreasing the near wellbore permeability by forming an ultra-low mud cake can strengthen the wellbore and mitigate further lost circulation problems. Very few studies have investigated filtration and filter cake build up under HPHT situations where effect of different mud particles and bridging solids can be analyzed.
This paper focuses on experimental methods quantifying water based muds used by the industry and investigating effects on particle bridging, filtrate invasion and permeability. To show the particle bridging effect, high temperature and pressure (HTHP) filtration tests were conducted at different time steps on sandstone cores with permeability ranging from 10 mD to more than 1100 md. The study also utilizes analytical models to calculate mud cake permeability for the tests using different mix design. The Scanning Electron Microscope (SEM) analysis conducted on the cores presents an expected trend of particle invasion with depth and time. The results from this study can be applied for designing wellbore strengthening fluids to mitigate wellbore stability and formation damage.
Modeling Pressure-Transient Data for Characterizing the Formation Damage in Water Injection Wells Operating above the Fracturing Pressure
Authors: BinAkresh Saud A. , Rahman N. M. 
Published: May 2015

Abstract
Injection wells are widely used in the petroleum industry to support sustained oil production. Water is injected into the reservoir for filling in the void space left by produced oil and to maintain the reservoir pressure. These injectors are frequently evaluated with fall-off tests to assess their injectivity with time. However, most fall-off tests on these wells are unexpectedly dominated by prolonged storage effects with a long unit-slope line on the log-log plot. As a result, the radial flow regime on the pressure derivative plot gets a little chance to develop within the stipulated test period. A high skin damage factor with an abnormally-high storage coefficient (e.g., 1 to 3 bbl/psi, which is one or two orders of magnitude larger than the typical values in regular wellbores) have to be introduced to the well test models to match the pressure behavior from these wells. This anomalous behavior suggests that the wellbore is connected to additional storage volume due to an induced fracture system around the well, having been intersected by a section of it. Apparently, these fractures close gradually after shutting in the well for a pressure fall-off test, manifesting as a prolonged storage effect in the data. This can be explained with the fact that most of the injectors inject water under fracturing conditions, which induce large fractures around the wellbore over time. The fracture system might play a role in taking the damage further inside the reservoir and complicate subsequent remedial work to restore well's injectivity.
In this paper, we will show and discuss several fall-off tests from water injection wells in giant oil fields in the Middle East. The results of these tests, conducted over the years, are to show how the entire test duration is progressively dominated by larger wellbore storage with increasing fracture volume around the wellbore. A changing wellbore storage model (Spivey and Lee) is useful in illustrating the phenomenon of dual storage effect – one due to the wellbore, followed by the other one due to the fracture volume. The model is also used to identify the damage conditions of two regions – one just around the wellbore and the other is located slightly deeper into the reservoir.
Addressing Microseismic Uncertainty from Geological Aspects to Improve Accuracy of Estimating Stimulated Reservoir Volumes
Authors: Yang Sheng , Chen Zhangxin , Wu Wei , Zhang Yonghua , Zhang Xinwen , Deng Haoyun 
Published: May 2015

Abstract
Unconventional resources development has had a great success in North America. But this success has not yet been duplicated in every tight oil or tight gas reservoir. A big challenge is how to correctly demonstrate and evaluate hydraulic fracturing outcomes, which are usually estimated by a stimulated reservoir volume (SRV). Microseismic data is a fundamental element to estimate a SRV. However, most microseismic signals are generated by shear fracturing, while hydraulic fracturing can induce tensile fracturing as well, which cannot be well reflected by microseismic data. A long distance between fracturing places and geophones can also make signals unclear and undetectable. Thus a sole microseismic interpretation has its own limitations. Integrating geological information and microseismic data can provide us with a valuable guide to increase the accuracy of an estimated SRV.
In this study, detailed geological data and well logs are applied to evaluate rock mechanical properties. As known, under the same hydraulic fracturing treatment conditions, a more brittle rock interval can form more fractures, and a rock interval with more natural fractures can generate more complex fractures. The near-wellbore zones are first evaluated by a rock mechanical index based on how the rock is prone to form hydraulic fractures. A rock mechanical model of a whole shale layer is further determined by a Pixel-Based reservoir modeling method. A rock mechanical index is used as a criterion to address the microseismic data uncertainty. Comparing a rock mechanical model with a SRV, some mismatched areas are located, the microseismic uncertainty is addressed, and the microseismic signal threshold criteria are then adjusted in these areas. As a result, a SRV in the mismatched areas is further modified based on a rock mechanical index value and a different signal dataset.
This approach has been applied in the Biyang shale oil reservoir, China. Compared with the successful Barnett marine shale formation, the target shale layer was deposited in a continental lacustrine environment with complex laminations and high heterogeneous rock mineral compositions. Comparing the SRV generated by original microseismic data with the newly SRV generated by applying this approach, the new one can precisely represent hydraulic outcomes and illustrate complex dual-permeability flow for unconventional reservoir development. The proposed approach is a good and valuable guide to increase the accuracy of estimating SRV.
Equation of State Coupled Predictive Viscosity Model for Bitumen Solvent-Thermal Recovery
Authors: Ma Mingxu , Chen Shengnan , Abedi Jalal 
Published: May 2015

Abstract
Exponential and polynomial viscosity correlations have been widely applied to model crude viscosities with temperature. These simple correlations are difficult to be applied to predict the viscosity of different solvent-diluted bitumen systems over a wide range of solvent composition. The Expanded Fluid viscosity model consisting of density as an input parameter can be coupled with an Equation of State in a compositional and thermal reservoir simulator. However, the accurate prediction of density using an EoS is the prerequisite to apply this viscosity model.
In this work, the expanded fluid theory was coupled with the simplified PC-SAFT EoS (Perturbed-Chain Statistical Associating Fluid Theory) to predict and correlate the rheology behaviour of bitumen/solvent systems. Athabasca and Peace River Bitumen was characterized using a proposed eight-pseudocomponent characterization method for PC-SAFT, which simply required distillation and molar mass data. The obtained density was then input into the viscosity theory to model viscosity. Viscosity predictions were obtained using zero viscosity binary interaction coefficients, whereas pressure-dependent and temperature-dependent viscosity binary interaction coefficients were adjusted to improve the effectiveness of mixing rules.
In the case of Athabasca Bitumen with CH4, C2H6, and CO2, the correlated solubility and density Average Absolute Relative Deviations (AARDs) were within 6.6 % and 2.3 %, respectively. Viscosity AARDs by prediction were within 55.4 %; whereas the AARDs were reduced within 13.5 % using pressure-dependent viscosity binary interaction coefficients. In the case of Peace River Bitumen with C2H6, C3H8, n-C4H10, n-C5H12, the predicted density AARDs were within 0.7 %. Viscosity AARDs obtained by prediction were within 24.9 %, and they were reduced within 8.4 % once using temperature-dependent viscosity binary interaction coefficients.