bluuebunny/crossref_metadata_2025_split huggingface dataset:
Reduced Cluster Spacing: From Concept to Implementation – A Case History
Authors: Deasy Michael , Brown Kenneth , He Jonathan , Lipscomb Wade , Ockree Matthew , Voller Katharine , Frantz Joe 
Published: October 2018

Abstract
This paper presents a case history and lookback on the Reduced Cluster Spacing (RCS) completion design that was initiated in 2012. We review results of the initial analyses used to demonstrate proof of concept, summarize key aspects of the completion design, and discuss execution and results of the initial pilot tests and subsequent field-wide implementation. We propose a method to incorporate results of RCS models into production forecasts, and quantify the impact of RCS designs on volumes and economics over time.
We begin by presenting proof of concept analyses used to justify the initial field pilot. We then discuss RCS field trials, commenting on key aspects of project design and operational execution. We compare RCS well performance to control wells using normalized production plots, discuss type curve (TC) forecasting for RCS wells, and touch briefly on more rigorous modeling of RCS completions. We present a methodology to incorporate results from rigorous models into simpler type curves suitable for quick economic analyses and volumetric comparisons. We conclude by reviewing the economic and production impact of RCS on production at the well level and field development level.
Case histories are presented demonstrating the use of a production normalization process to assess the value of different completion designs. We demonstrate that RCS completion designs have been successful in terms of both volumes uplift and economic performance. We describe positive and negative aspects of the route taken to implement this strategy in the field. We conclude that the use of "uplift factors" derived from modeling can be used to efficiently incorporate detailed model findings into typical engineering workflows for volumes and economics forecasting. As a result of the work presented in this paper, RCS completions have become the standard in our Marcellus wells.
This lookback will present a method to effectively demonstrate proof of concept for new completion designs and assess the field implementation of novel completion strategies. This method is demonstrated by quantifying the value of reduced cluster spacing achieved in the Marcellus. We also provide a simple way to incorporate complex model results into every day engineering and economic forecasts.
Flowback Fracture Closure of Multifractured Horizontal Wells in Shale Gas Reservoirs
Authors: Zhang Fengyuan , Emami-Meybodi Hamid 
Published: October 2018

Abstract
In multi-fractured horizontal wells (MFHW), fracture properties such as permeability and fracture half-length significantly deteriorate during early production, which negatively affects gas production from shale reservoirs. Therefore, it is crucial to evaluate the temporal changes in fracture properties based on production data. This paper presents a workflow in which both flowback and long-term production data are used to quantitatively evaluate hydraulic fracture closure and changes in the fracture properties. In addition, we develop a two-phase semi-analytical model based on rate transient analysis (RTA) that assumes boundary dominated flow during the flowback period. The proposed workflow consists of three steps. First, we used the flowback data to calculate fracture properties, such as initial fracture permeability and fracture half-length, by employing the two-phase semi-analytical model. Then, we calculated initial fracture permeability by using a single-phase bilinear flow model as well as the fracture half-length and matrix permeability by using a single-phase linear flow model from the long-term gas production data. These models consider pressure dependency of permeability. Last, we compared the results that are calculated from both flowback and long-term production data to evaluate fracture closure and its effects on fracture permeability. We validated the semi-analytical flowback model and the workflow against numerical simulations. The results show that the developed model is capable of predicting fracture properties and evaluating fracture closure. Furthermore, the proposed workflow provides quantitative insights on the performance of fracture stimulation and is able to closely estimate permeability modulus using flowback and long-term production data instead of conducting laboratory experiments.
Effect of Degradable Fiber Composition and Shape on Proppant Suspension
Authors: Collins Nick Allen , Grim R. Gary , Ghosh Koushik , Dorgan John R. 
Published: October 2018

Abstract
The ability of degradable fibers to reduce the settling rate of ceramic proppant in a guar-based solution was studied as a function of fiber composition and shape. Various cellulose ester fibers were benchmarked against a PLA standard.
Aqueous (2 wt% KCl in DI water) mixtures of degradable fiber, ceramic proppant, and guar were consistently mixed then allowed to settle. The position of the interface between the solids-rich bottom layer and solids-poor top layer was measured as a function of time for various fiber compositions, shapes, and loadings. Settling experiments were also repeated to determine measurement error. Viscosity measurements were performed both to determine appropriate guar loading and to investigate the effect of fibers on viscosity.
Consistent with recent results published in the patent literature for PLA, fiber shape was found to have a strong effect on proppant suspension. However, these effects went well beyond those found for aspect ratio and degree of crimping reported previously. Indeed, fiber cross-sectional shape was found to have a very strong effect with "X" and trilobal shapes showing better proppant suspension capability than round fibers. Fiber loading with shaped fibers could be reduced up to half of that round fibers with the same proppant suspension performance. The degradable polymer composition may play some role in proppant suspension but it appears to be secondary relative to that of fiber shape.
Degradable fibers with improved performance should enable broader consideration of their use for proppant transport, proppant suspension, and heterogeneous proppant placement in fiber-based hydraulic fracturing. Other stimulation applications may also value alternative degradable materials.
Quantification of Fracture Surface Roughness and Its Insights to Mechanical Rock Properties Determination Using Image Analysis Techniques
Authors: Gong Yiwen , El-Monier Ilham 
Published: October 2018

Abstract
During the hydraulic fracturing process, the rough surface of fractures and the viscous proppant suspension flow bring great challenges to the distribution of proppants evenly at the fracture thin apertures. As a result, a detailed understanding of the effect of surface roughness on proppant sedimentation seems essentially indispensable. Apart from that, how the roughness of Nano-scale conduits and their orientations, such as microfracture channels, affect the flow through the damaged fracture process zone (FPZ) have not been well understood.
A newfangled developed algorithm using image analysis software (ImageJ) is applied to characterize the morphological features of the damaged fracture system, including surface roughness, microcrack types and microcrack density indicators. Hydraulic fracturing experiment is conducted on a Tennessee sandstone core using a triaxial loading system. The fractured samples are ion milled, and its cross section plane images are recorded by scanning electron microscope (SEM). Statistical analysis of surface roughness, the degree of damage at FPZ, the density of microcracks and effective connection indicator of microfractures to the main fracture are quantitatively investigated, in addition to Young's modulus and Poisson's ratio.
We found that the higher roughness of microfracture network significantly enhances the effective conduits open to fluid flow while taking the density of the microfracture within FPZ into account within the fracture processed region, depending upon how much damage is presented. In other words, the overall ease of fluid delivery to the main fracture essentially depends on the level of the damage in FPZ. The heavily deformed rock grains cause a partial blockage at the fracture surface and will be detached on the main fracture. The leftover is the induced intercrystalline microfracture network in the vicinity of the main fracture. Additionally, mechanical moduli were interpreted by image analysis, where a novel approach was developed to calculate the mechanical rock properties. The results from image analysis were compared to other failure criteria and fracturing pressure data interpretation. We also validated the obtained mechanical properties by collating the literature records.
The microfracture network creates the significant incremental amount of fluid conduits to hydrocarbons. The better understanding of the fracture network serves as a valuable guide to the fracturing job design and managing the damaged FPZ. This novel approach will commit to supporting the lab measurements, gives field preliminary mechanical property assessment and lower the cost needed for hydraulic fracturing design.
Drawdown Management Optimization from Time-Lapse Numerical Simulation
Authors: Crespo Pablo Agustin , Cuervo Sergio 
Published: October 2018

Abstract
The Choke Management has been one of the "hot topics" in Unconventional Reservoirs since the negative impact in using an accelerated flowback has been demonstrated in many documented cases. Modern production practices have migrated from a Choke Management to a Drawdown Management Strategy to improve the control on the effective net stress over the proppant in order to prevent hydraulic fracture conductivity damage and maximize ultimate recovery. The strategy optimization is a complex problem that reservoir engineers are still trying to solve using different tools from empirical observations up to complex reservoir simulators that includes reservoir physics and the most advanced rock mechanics. This work contributes introducing an innovative workflow using a state of the art non-coupled numerical simulator, with the addition of time-steps one-way coupled calculations.
The methodology consists in using a commercial reservoir simulator to History Match Completion Treatment Pressures and then Production. Once this first step has been completed, a Pore Pressure Grid is extracted at different times and then used to calculate changes in the minimum stress according to the isotropic poroelastic equation. Finally, the effective net stress over the proppant is calculated. This process is repeated with different Drawdown Management Strategies until the optimization.
The complete workflow is introduced in a real case example where a robust dataset was available for a horizontal well. Finally, some assumptions and considerations are discussed and conclusions are extracted from this study.
A Workflow to Investigate the Impact of the Spontaneous Imbibition of a Slickwater Fracturing Fluid on the Near Fracture Face Shale Matrix
Authors: Al-Ameri Aymen , Gamadi Talal , Ispas Ion , Watson Marshall 
Published: October 2018

Abstract
The present study used the workflow presented in Al-Ameri et al. (2018a, 2018b) to evaluate the impact of the fracturing fluid imbibition on the near fracture face shale matrix. Al-Ameri et al. (2018b) used carbonate-rich outcrop shale core samples that had very low and no clay content. However, in this workflow, core samples from the Barnett reservoir that had an abundant amount of quartz and clay were used. The primary aspect of the current study is to investigate the mutual effect of the shale rock petrophysical properties and the polymer adsorption; moreover, the effect of the shale mineralogical composition on the rock prone to adsorb polymer. The effect of the non-ionic surfactant on the imbibition rates, and also the anisotropy on the rock ability for polymer adsorption were also investigated. The results of this workflow were compared to the Marcellus samples results presented in Al-Ameri et al. (2018b).
The workflow incorporates conducting three systematic imbibition experiments for a same shale core sample using brine, slickwater, and brine again. The sample brine permeability was measured before and after the imbibition experiments using a constant rate steady-state permeability setup.
The results showed that the polymer adsorption reduces the brine spontaneous imbibition volumes. Moreover, the shale petrophysical properties could dominate the polymer adsorption more than the mineralogical composition.
Adding a non-ionic surfactant to the slickwater enhanced the imbibition rate considerably into both of the Barnett and Marcellus shale samples, and that improves the fluid flowback in these shales.
The bedding planes and their orientation are among the factors that control the effect of the polymer adsorption on the fluid imbibition rate. The more obvious are the bedding planes, the higher impact of the polymer adsorption on the fluid imbibition rate. However, the petrophysical properties have more effect on the shale prone to adsorb the polymer than the bedding plane orientation.
The effect of the polymer adsorption slightly increased the capillary pressure curve. However, as the porosity and permeability increase, the effect of the polymer adsorption on the capillary pressure increases. In comparison to the Eagle Ford shale, the Barnett and Marcellus shales had lower capillary pressure, and that could be one of the reasons of their higher fluid flowback. The impact of the polymer adsorption on the water relative permeability was less for the Barnett sample in comparison to the Marcellus sample because of its lower porosity and permeability.
Application of Multi-Functionalized Surfactant to Enhance Hydrocarbon Production in Tight Oil & Gas Formations Yields Successful Results
Authors: Quintero Harvey , Hawkes Robert , Mattucci Mike , Sessarego Sebastian , O'Neil Bill , Zhang Kewei 
Published: October 2018

Abstract
Oil and gas shale hydraulic fracturing designs for new wells drilled typically call for water volumes as high as 50,000 m3 (314,000 bbls). The cleanup of these massive water volumes during flowback must be efficient and minimize fluid invasion into the matrix. Once the saturation of the invaded water zone is reduced to the lowest possible level during flowback (cleanup operations), hydrocarbons can flow freely into the wellbore. However, the flowback behavior in unconventional reservoirs is quite different than in conventional reservoirs where soakback and slowback techniques are implemented. It is not uncommon for these wells to be shut in or for weeks or even months following the hydraulic fracturing treatment. Chemical and surfactant flowback enhancers such as microemulsions and nano-surfactants are additives typically used in hydraulic fracturing to assist in flowback design and improve load fluid recovery as they minimize fracture face damage due to water blockage.
In this paper, we describe the successful field application of a multi-functionalized surfactant (MFS) that significantly outperformed common surfactant chemistry when applied to mixed-wettability shale core samples in laboratory Amott cell tests. The results from the laboratory testing were reflected in field trials: the relative permeability to hydrocarbon was increased and production was enhanced.
Integrating Microgel-Low Salinity Waterflooding to Improve Production Profile in Non-Crossflow Heterogeneous Reservoir
Authors: Alhuraishawy Ali K. , Bai Baojun , Wei Mingzhen , Almansour Abdullah , Alsaba Mortadha , Elsharafi Mahmoud 
Published: October 2018

Abstract
The oil recovery from fractured reservoirs is usually low and the early water breakthrough is one result of the fractured reservoir. Two enhanced oil recovery (EOR) methods, low salinity water flooding (LSWF) and micro-gel, have recently drawn great interest from the oil industry. We integrated both methods into one process. The objective of this study was to test how the combining method could reduce production rates from the fractured layer and improve the production rate from the non-fractured layer through laboratory experiments.
The parallel non-crossflow models, which were made of sandstone cores and two core holders, were built. The gel strength, water salinity, gel particle size, and sandstone permeability effects on oil recovery, production rate, and gel penetrations were studied. Sodium chloride (NaCl) was used for brine flooding and preparing swollen PPG. Two brine concentrations (1.0, and 0.01 wt. % NaCl) were used for the experiments. A light mineral oil was used. A flow rate of 0.5 ml/min. was used to inject the brine into the parallel non-crossflow models before and after the gel was placed into the fracture. The gel was injected into Outlet 1 to fill out the fracture at a flow rate of 2.0 ml/min until the gel injection pressure reached 500 psi. The optimum water salinity for the application of the coupled method was determined through laboratory experiments to be 0.01 wt. % NaCl because this gave the highest gel penetration into the partially fractured layer. However, the best water shut-off was obtained when the water salinity was 1.0 wt. % NaCl. The incremental oil recovery was almost the same in both 1.0 and 0.01 wt. % NaCl water salinity. When the gel particle size decreased, the water shut-off from the partially- closed fracture layer and the incremental oil recovery from the matrix were increased. This application had no significant effect when the core permeability was low because there was not much of an effect on the production rate ratio after gel treatment. From the laboratory experiments, we concluded that the PPG application might be more successful it is swelled in a low brine concentration.
Acid Fracturing of Low Permeability Carbonate Formation Lessons Learned
Authors: Rafie M. , AlOtaibi F. M. , Al-Dahlan M. N. , Suwadi S. H. 
Published: October 2018

Abstract
This paper provides information on the journey and lessons learned from one well’s acid MSF from the required lab design, through on-site fluids’ QA/QC findings, to the 4 days of flow back sample analyses indication. Several pre-job lab assessments were conducted to: Optimize the diversion fluids rheology, assure sufficient acid corrosion inhibition, and eliminate the incompatibility issue between all pumped fluids and the reservoir acid sensitive crude oil. Additionally, on-site QA/QC critical findings for each stage fluid resulted in taken corrective actions for assured acceptable concentration and stability of mixed acid recipes and the adequacy of fracturing fluid viscosity. The 4 days of flow back samples analyses revealed the need for a longer cleanup time.
In addition, ion composition of flowback samples were used to identify areas of improvement and enhancement in fracturing fluid design. The successful massive multistage acid fracturing was achieved with over a two-fold increase in production rate. A major part of the success is attributed to a scheme of the fluid’s optimization, quality control, on-site QA/QC and cleanup monitoring progress. In addition, on-site fracture treatment evaluation for each stage individually has a major impact on operational success utilizing pressure sensors response and fracturing simulation software.
Finally, a comprehensive analysis for an acid fracture job and the lessons learned from this operation will be shared. The journey of lessons learned started from the lab to the field, and back to the lab, with strong guidelines for all future acid fracturing jobs in similar oil fields
Probabilistic Production Forecasting and Reserves Estimation in Waterflooded Oil Reservoirs
Authors: Nazarenko Maksim 
Published: October 2018

Abstract
The importance of uncertainty quantification and risks assessment in the petroleum industry cannot be overstated. Uncertainty will always be present in production forecasts and reserves estimates. Underestimation of uncertainty when estimating reserves and profitability of projects can lead to poor decision making and disappointment.
Water Displacement Curve (WDC) models are alternative to Decline Curve Analysis (DCS) models in waterflooded oil fields. These curves allow engineers to estimate reserves and forecast production performance in waterflooded oil reservoirs taking into account either liquid or water production. Compared with DCA, WDC models are expected to perform better in forecasting oil production in waterflooded oil fields.
In this study I applied WDC models probabilistically using Bayesian methodology and Markov Chain Monte Carlo (MCMC) stochastic simulation. I also developed a Multimodel approach based on eleven WDC models to quantify uncertainty in production forecasts by assessing differences in matches and forecasts provided by each model.
Both Multimodel and MCMC with WDC models were calibrated and compared to MCMC with DCA method which was recently developed and introduced by Gong et al. (2011). Reliability of the developed methods was assessed using production history of 100 wells from actual waterflooded oil fields. I performed hindcast studies in which I assumed that some fraction of the actual historical production data is known (6, 12, 24 and 36 months) and the rest of the actual production is unknown (5 - 7 years). I then matched the assumed known production fraction of the history and forecasted production to the end of the actual historical period. The cumulative production at the end of the hindcast is compared to the actual cumulative production at this time to test the probabilistic reliability of the methodology when production history is limited. The study showed that both developed methods are well-calibrated probabilistic methods. Also, computer software was developed during this research to make the process of calculations more convenient.
Coupling Low Salinity Water Flooding and Steam Flooding for Sandstone Reservoirs; Low Salinity-Alternating-Steam Flooding (LSASF)
Authors: Al-Saedi Hasan N. , Flori Ralph E. , Alkhamis Mohammed , Brady Patrick V. 
Published: October 2018

Abstract
Low salinity water flooding and steam flooding are two novel combination flooding methods that were combined due to the important role of both methods in increasing oil recovery (especially heavy oil). Low salinity flooding was examined by many laboratory and field works and showed an interesting result. Steam flooding was tested on heavy oil fields and the heavy oil recovery increased by reducing oil viscosity. Although the steam showed an improvement in heavy oil recovery, the density difference between steam and heavy oil raised a problems with steam gravity override, channeling, and early breakthrough. For that reason, we developed the low salinity alternating steam flood (LSASF) in order to gather the benefits of low salinity, reduce oil viscosity by steam, and prevent the steam problems mentioned earlier. The laboratory experiments showed that the optimum scenario was Scenario (3). The shorter the injected cycles, the more oil recovery.
This combination of echnology can solve the steam flooding problems and support the steam by LS water, which has the ability to increase oil recovery.