bluuebunny/crossref_metadata_2025_split huggingface dataset:
Gibbs Free Energy Minimization for Reactive Flow in Porous Media
Authors: Venkatraman Ashwin , Lake Larry W. , Johns Russell T. 
Published: September 2013

Abstract
Acid gases (CO2/H2S) injected in aquifers for continuous hydrocarbon production from sour gas fields (gas reserves with acid gas contaminants) can react with the ions present in the brine. The solubility predictions are then, quite different than those without reactions. Accurate solubility estimates in the presence of such reactions are integral towards developing an effective acid gas disposal strategy for continuous production from these fields. Also, the modeling of CO2 injection in oil reservoirs entails complex interplay of flow, geochemical reactions and hydrocarbon phase behavior. The geochemical reactions affect the component mole numbers, which can change the number of hydrocarbon phases and/or affect the distribution of components in them. In this research, we propose the Gibbs free energy minimization algorithm that integrates geochemical reactions and phase behavior to find equilibrium compositions for these two applications. We use this algorithm to find equilibrium compositions for not just pure phase equilibrium (without reactions) but also phase and chemical equilibrium (with reactions). While the number and composition of the hydrocarbon phases may vary; we assume all the geochemical reactions are at equilibrium. In the first application, we use this algorithm to estimate solubility of acid gases (CO2 and/or H2S) in pure water as well as CO2 solubility in high salinity brine. The algorithm predicts the solubility for binary systems of CO2- H2O and H2S-H2O at high pressures and at temperatures upto 50°C. The use of Pitzer's activity coefficient model for aqueous phase components also helps predict the solubility of CO2 in high salinity brine. In the second application for hydrocarbons, we investigate the impact of geochemical reactions on the phase distribution of CH4-CO2-H2O mixture. We observe that the geochemical reactions do not change the equilibrium phase mole fractions at 50°C in the pressure range 0.1–20 MPa.
New Approach to Identify Analogue Reservoirs
Authors: Rodriguez H. Martin , Escobar E. , Embid S. , Rodriguez N. , Hegazy M. , Lake Larry W. 
Published: September 2013

Abstract
The identification of analogous reservoirs is an important step in planning the development of a new field, because the information available about the new areas is usually limited or even nonexistent. Traditionally the search for analogous reservoirs has been made by experienced geoscientists, but this practice is subject to availability of this experience and the results are heavily dominated by geology. In this paper we present a systematic and unbiased procedure to search for analogous reservoirs, based on information contained in a validated large database of reservoirs parameters, both engineering and geologic. Each reservoir has its own "fingerprint" characterized by the set of its own properties, which differ from one reservoir to another. The method uses multivariate statistical techniques to find a unique and reproducible list of reservoirs with fingerprints that are most similar to the selected target. The flexibility of the method allows variation of the similarity function (weights) and evaluation of different scenarios (static, dynamic, PVT behavior, etc.).
Our method basically consists of four steps: Data Preprocessing, Key Parameters Selection, Multivariate Analysis, and Similarity Ranking. The first step consists of the analysis and preprocessing of the available database. In the second step, Key Parameter Selection, variables with largest impact on the case to be evaluated are identified. The third step, Multivariate Analysis, applies several multivariate techniques such as principal component analysis (PCA) and cluster analysis. Finally, in the Ranking step, we apply a similarity function to the group of previously selected "analogous reservoirs", generating a similarity ranking of analogous reservoirs.
To validate this new method we use the Casablanca oil field as a target reservoir. Casablanca is a mature carbonate reservoir very well known by Repsol whose experts identified four analogues for this target. The new developed method was independently applied in this case to obtain 19 analogous reservoirs sorted by similarity criteria. The maximum similarity found was 85 % for the Amposta Marino reservoir, one of the independently identified analogous reservoirs given by the business unit team. Moreover, the four analogous reservoirs previously identified by the business unit team were between the first ten positions in the similarity ranking. These results are highly encouraging as it captures the know-how of the experts and ensures a reproducible response, regardless of the user expertise.
The most relevant advantage of this new method is that it is based on a similarity function that takes into account all the weighted key parameters simultaneously, instead of sequential filters used by some commercial software. As a result, the procedure we present in this work will support the predictive search of missing properties for the target reservoir, reducing the uncertainty for decision making.
Field Deployment of Fracturing Site Sand Fill Dust Mitigation System
Authors: Anderson T. , Parks A. , Arellano J. 
Published: September 2013

Abstract
Use of silica sand as a proppant has grown dramatically over the last decade with the rise in production of unconventional resources. Large volumes of silica sand are used as a proppant to hold open formation fractures. The sand is pneumatically conveyed into frac sanders before being moved again into a blender where it is mixed into the fluid to be pumped down hole. During these operations, silica dust enters the air and poses hazards to those working on site. The exposure and inhalation of silica dust can cause silicosis, the most widespread industrial disease in the world. Silicosis has been known of for hundreds of years, traditionally found in workers in the sand blasting, mining and construction industries. While the causes of silicosis are known, the disease is incurable once developed. Furthermore, the disease can take up to 15 years to materialize, making workers currently exposed unaware of the potential dangers they are presently in. According to a recent U.S National Institute for Occupational Safety and Health (NIOSH) study, many frac sites exposure levels exceed, sometimes by a factor of 10, the NIOSH Recommended Exposure Limit (REL) to crystalline silica.
In an effort to combat the increasing exposure to silica dust during fracture operations dust collection equipment has been developed. SPE163528 discussed the development of this equipment and mentions other opportunities for dust mitigation. This equipment has now been deployed to the field. This paper discusses adjustments to the equipment and further realized opportunities for dust mitigation. These include helping avoid problems such as personnel over-filling the sand bins and addressing pneumatic flow rates beyond the design limit of the dust collection system.
A Simplified Slug Flow Model for Highly Viscous Oil-Gas Flow in Horizontal Pipes
Authors: Brito R. , Pereyra E. , Sarica C. , Torres C. 
Published: September 2013

Abstract
Typically pressure drop prediction of gas-liquid flow in pipes is carried out by mechanistic models. A proper prediction of the pressure drop requires prior identification of the flow pattern. Previous studies indicate (Gokcal, 2003 and 2008) that the most likely flow pattern for highly viscous oil is slug flow, which consists of a liquid slug region, followed by a bubble or film region. For highly viscous oils, a simplification of slug flow models is proposed based on experimental observations. This simplification is based on the fact that the pressure drop in the slug region is much larger than the pressure drop in the film region. The developed model shows fair agreement when it is compared against the data with oil viscosities from 40 to 580 cP. This model is applicable for two-phase flow Reynolds number up to 2000, which are common values in heavy oil production systems and does not require iterative solution.
An Excess-Bubble-Point-Suppression Correlation for Black Oil Simulation of Nano-Porous Unconventional Oil Reservoirs
Authors: Firincioglu T. , Ozgen C. , Ozkan E. 
Published: September 2013

Abstract
The average pore size in unconventional, liquids-rich reservoirs is estimated to be less than 100 nm. At this nano-pore scale, capillary forces play an important role on phase behavior that is not considered in conventional PVT studies. Confinement on phase behavior of black-oil fluids manifests itself as bubble point pressure suppression, extension of the undersaturated portion of the formation volume factor curve, and alteration of the equilibrium gas composition. Studies show that the magnitude of the bubble point suppression is more than the capillary pressure and may amount to hundreds of psi. These phenomena can be modeled through compositional solution of the phase behavior at differing gas- and oil-phase pressure values that are due to capillary pressure. However, black-oil simulators cannot perform the compositional phase behavior calculations to estimate the total bubble point suppression due to confinement. In this study a correlation that expresses the bubble point pressure suppression as a function of the capillary pressure and the solution gas oil ratio (Rs calculated through conventional PVT which is the input in black oil simulator) was developed, such that it can be used as a simulation model input. The correlation data was based on three unconventional oil samples evaluated at different saturation pressures and compositions. To use the correlation, a modified black oil simulator that can handle the PVT data at different oil- and gas-phase pressure values is required. The source code of the black oil simulator used in this study was modified to include the total bubble point suppression into the PVT calculations. The impact of the confined phase behavior on flow was quantified through simulation runs. The results showed that the grid blocks with different capillary pressure values reach the bubble point at different times. During depletion, the grid blocks with higher capillary pressure values remained in undersaturated conditions longer, impacting the gas production and pressure profiles.
Estimation of Fluid Composition from Downhole Optical Spectrometry
Authors: Indo Kentaro , Hsu Kai , Pop Julian 
Published: September 2013

Abstract
During formation tester operation, the use of downhole optical spectrometry has been proven to be essential for reservoir fluid characterization. Apart from the intrinsic value of fluid profiling, obtaining fluid properties downhole in real time is of particular interest since the results may impact the decision-making process during sampling and ultimately the success of the sampling operation.
A new methodology predicts petroleum fluid composition from optical spectra acquired with wireline or while-drilling formation testers. The method comprises fluid typing, computation of fluid composition and estimation of data specific uncertainty. The fluid typing algorithm is capable of categorizing a sample into three fluid types: gas, retrograde gas and oil. Based on the fluid type identified, the appropriate mapping matrix, which transforms optical spectra into compositions, is selected. The mapping matrix is derived from a database consisting of optical spectra, compositions and pressure/volume/temperature (PVT) properties of a wide variety of petroleum fluids. The outputs of the composition algorithm are the weight fractions of the hydrocarbon pseudo components, C1, C2, C3, C4, C5 and C6+, and CO2. The composition is used to estimate the gas-oil ratio (GOR) by means of an artificial neural network algorithm. As a measure of uncertainty, confidence intervals are computed for the predicted components of the composition and GOR. All results are available during acquisition of the data.
The accuracy of the algorithm in estimating composition, GOR and their associated confidence intervals was assessed by comparing the results of the predictions against laboratory-derived results. Several field data sets were analyzed and the results were compared to the results obtained by PVT laboratories on the same samples. The estimated composition and GOR showed very good agreement with PVT results. Furthermore, the algorithm provides more accurate estimates of composition and GOR than are available with current downhole optical spectrometers.
Cross-Play Shale Gas Well Performance Analysis
Authors: Nair Narayan , Miller Mark A. 
Published: September 2013

Abstract
Shale resource plays often present formidable reservoir management challenges, particularly with regard to capital utilization and allocation. In spite of significant efforts to measure and analyze key reservoir and completion data, uncertainty typically remains in the physical characteristics of the stimulated reservoir volume (SRV) accessed by hydraulic fracturing, namely: shale permeability, fracture spacing, SRV spatial dimensions, and gas-in-place.
In this study, well performance histories of several hundred wells spanning the Haynesville, Woodford, Barnett, Horn River, Marcellus, Fayetteville and Montney shale plays were investigated with a common and consistent analytical framework that determined: a) a well productivity measure during infinite-acting linear flow, b) completion pressure losses (between sandface and bottomhole), and c) apparent original-gas-in-place in the SRV. Parameters determined from the analyses are key indicators of the combined result of reservoir quality and hydraulic fracture performance. Results of this multi-well cross-play study provide information about both inter- and intra-play variability and commonality.
A large proportion of the wells (85%) showed prolonged periods of linear transient flow, indicative of low matrix permeabilities. Wells of higher productivities tended to go into depletion flow earlier, which could be consistent with either high matrix permeability or large fracture surface areas that are close together (complexity). Completion pressure drops were not observed as the dominant productivity-loss mechanism. Productivity of wells during infinite-acting flow normalized by the total mass of proppant used in each well, an SRV creation efficiency, and the original-gas-in-place in the SRV for all wells in this study showed log-normal distributions. The 100-day flow efficiency of the completions in these wells showed a truncated normal distribution.
Recognizing the variability in the reservoir characteristics of the studied shale plays, and SRV's that were outcomes of diverse completion practices, the observed predictability in key well performance characteristics is remarkable. The distributions presented in this paper can be used to improve well performance predictability, help identify sweet spots for drilling, establish relatively narrow ranges of a priori well performance characteristics (therefore reducing uncertainty at undeveloped well locations), improve fracturing practices, and provide support for decisions of capital allocation.
Causal Analysis and Data Mining of Well Stimulation Data Using Classification and Regression Tree with Enhancements
Authors: Bhattacharya Srimoyee , Maucec Marko , Yarus Jeffrey , Fulton Dwight , Orth Jon , Singh Ajay 
Published: September 2013

Abstract
The well treatment program is an important part of the field development plan, and certain variables, such as job pause time (JPT) and fracture screenout, can affect its efficiency. JPT is the time during which pumping is paused in between subsequent treatments of a job. Screenout occurs because of a sudden restriction of fluid flow inside the fracture and through the perforation. The objectives of this work are to investigate whether, from existing data, it is possible to find patterns in significant variables that affect the extreme values of JPT in a particular region and what is the most critical variable causing screenout. The answers are sought by applying a classification and regression tree (CART) to both categorical and continuous variables in the database. The practical application of CART is presented using case studies containing JPT and screenout. Significant variables are found that affect the response variables, and predictor variables are ranked in the hierarchal order of their importance. Such information can be used to control predictor variables that cause high JPT or screenout.
The results are outlined in an intuitive way, including categorical, continuous, and missing values. Because CART is a data driven, deterministic model, one cannot calculate the confidence interval of the predicted response. The confidence in results is purely based on the historical values, and the accuracy of the result produced by a tree model depends on the quality of recorded data measured in terms of volume, reliability, and consistency. The prediction capability of CART is enhanced by using the normal score transform (NST) and by dividing the large dataset into smaller groups using clustering. The approach presented in this paper analyzes a dataset under limited information and high uncertainty and should lead to developing methodology for generating proxy models to find future success indices (e.g., one for drilling efficiency or production from a fracture). This could standardize stimulation and generate decision practices to save costs in field development and the optimization process.
Experimental Investigation of Propped Fracture Network Conductivity in Naturally Fractured Shale Reservoirs
Authors: Wen Qingzhi , Jin Xiaochun , Subhash N. Shah , Li Yang 
Published: September 2013

Abstract
Microseismic mapping of horizontal well multi-stage fracturing of shale reservoirs has proven that the geometry of fracture is not planar as assumed/observed in conventional reservoirs, but rather a complex connected fracture network. The network is assumed to be constructed by three basic fracture types (Horizontal and vertical fractures parallel to, and vertical fracture perpendicular to flow direction - Type I, Type II, and Type III fractures respectively). A new fracture test cell is designed and constructed for investigating propped fracture network conductivity similar to the API standard fracture conductivity test cell that is presently used by the oil and gas industry.
In the experimental investigation, nitrogen gas is selected as fluid for safety reasons and also its physical properties are similar to methane gas. Marble is selected as a substitute for shale in constructing the fracture network in laboratory tests because of its similarity with shale in both permeability and wettability. Shale samples cannot be easily obtained and shale slices are difficult to prepare. A lightweight (1.5 g/cc), small size proppant (40-70 mesh) is selected because of its wide use in shale gas development and ease of transportation in the fracture network. The fracture widths of the three fracture types are assumed to be equal in the same propped fracture network. Twenty-two groups of successful experiments are selected to calibrate equipment, investigate the influence of actual fracture width, number of each fracture type, and closure stress on propped fracture network conductivity by selecting various combinations of fracture patterns, confining pressures, and proppant concentrations. Darcy's law is employed in calculating propped fracture network conductivity by introducing concepts of equivalent fracture width, equivalent proppant concentration, and equivalent fracture conductivity.
The experimental results showed that the modified API fracture conductivity test cell was calibrated well against the API standard cell. The deviations were in the range of 4.4% to 8.1%. The value of equivalent propped fracture conductivity measured by the modified API fracture conductivity test cell is acceptable. It was observed that the propped fracture network conductivity (1) decreases with increasing closure stress, and reached a limiting value when closure stress exceeded a critical value and (2) increases with increasing actual fracture width (proppant concentration). Furthermore, increasing number of Type-I and II fractures will increase propped fracture network conductivity, and Type-II fracture is more dominant than Type-I fracture, but Type-III fracture does not affect propped fracture network conductivity as significant as other two fracture types do.
FreezeFrac Improves the Productivity of Gas Shales
Authors: Enayatpour S. , Van Oort E. , Patzek T. 
Published: September 2013

Abstract
With rapid depletion of conventional petroleum supplies and due to energy security concerns, the world is increasingly turning its attention to unconventional hydrocarbon reservers such as oil shales, gas shales, tight gas sands, coalbed methane, and gas hydrates. Despite the abundant unconventional reservers, the production is still hindered by many obstacles including lack of technology and knowledge of the physics of flow in tight porous media. Flowing the tightly-locked hydrocarbon to the well in such formations, unlike the conventionals, requires a large number of inter-connecting pathways for flow. The existing in-situ cracks in rock have to be connected in order for the hydrocarbon to flow into the wellbore. In this paper we go over the basic mechanisms of rock fracture in micro and Macro levels and then study the two parameters whose variations could reduce the effective stress and lead to rock fracturing. We then discuss the effect of inhomogeneity on the fracture load and show that the dominant load for thermal fracturing is the tensile stress. There are three governing equations of stress, heat transfer, and flow which should be solved in a coupled fashion, for which we are using the finite element software packages. Assuming that thermal cracks increase the permeability of rock in the near wellbore zone by 10-10,000 times, we show the impact of rock stimulation by thermal shock on cumulative production of gas from a sample case of a wellbore placed in a tight formation. The improved recovery for the sample case is 16%.