Initial Gas Production Research Articles

Effects of Aqueous Solubility and Geochemistry on CO2 Injection for Shale Gas Reservoirs

In shale gas reservoirs, CH4 and CO2 have finite aqueous solubilities at high-pressure conditions and their dissolutions in water affect the determination of the original gas in place and the CO2 sequestration. In addition, the dissolution of CO2 decreases the pH of connate water, and the geochemical reactions may thus occur in carbonate-rich shale reservoirs. The comprehensive simulations of this work quantify the effects of aqueous solubility and geochemistry on the performance CO2 huff-n-puff process in shale gas reservoir. Accounting for the aqueous solubility of CH4 increases the initial natural gas storage and natural gas production. The effect of the aqueous solubility of CO2 enables to sequester additional CO2 via solubility trapping. Considering the geochemical reactions, the application of the CO2 huff-n-puff process causes the dissolution of carbonate minerals and increases the porosity enhancing the gas flow and the gas recovery. Incorporation of geochemistry also predicts the less CO2 sequestration capacity. Therefore, this study recommends the consideration of aqueous solubility and geochemical reactions for the accurate prediction of gas recovery and CO2 sequestration in shale gas reservoirs during the CO2 huff-n-puff process.

A dynamic prediction model of pressure-control production performance of shale gas fractured horizontal wells and its application

For clarifying the inherent relation between relieving fracture closure and improving the EUR by adopting the pressure-control production system for shale gas fractured horizontal wells, and the significance of pressure-control production for gas reservoir engineering, a dynamic formation–fracture coupling prediction model for production performance of fractured horizontal wells was established and solved, with the finite conductivity fracture as basic flow unit and the variable stress sensitivity coefficient introduced. Through a comparison of the calculated results from the established model, classical model and numerical modeling by the Saphir software, the effect of characteristic parameters of stress sensitivity and pressure-control production system on the production performance of fractured horizontal wells was analyzed and verified in two wells. The results show that (1) the calculated results from the established model are basically consistent with those from the classical model and the numerical modeling by the Saphir software; (2) the existence of stress sensitivity makes the fracture conductivity decline with the production of gas wells, which leads to the decrease of cumulative gas production; the greater the stress sensitivity, the greater the decrease of cumulative gas production; (3) although the initial gas production and cumulative gas production of shale gas gained by the pressure-control production system are low compared with those by the pressure-release production system, the ultimate cumulative gas production is higher. Thus, it is more reasonable to adopt a long-term pressure-control production system for shale gas fractured horizontal wells. In conclusion, the research results provide a theoretical support for the popularization of pressure-control production system of shale gas wells.

Biodiesel Co-products Modified the Rumen Parameters of Feedlot Lambs but did not Change Methane Production In Vitro*

Background: Intensification of livestock is a strategy that increases productivity, but the diets used to increase animal production efficiency are composed mainly of corn and soybean, thereby increasing competition between animals and humans for the same food crops. This study evaluated nutrient intake, apparent digestibility of dry matter (DM) and nutrients, kinetics of gas production, and concentration of volatile fatty acids on diets with or without inclusion of biodiesel co-products formulated for feedlot lambs. So, the hypothesis is that replace of traditional ingredients by biodiesel co-products changes rumen parameters and methane emissions.Material, Methods & Results: The experiment was developed in São Paulo State University (Unesp), Jaboticabal/SP, Brazil, in Sheep Production Laboratory, which is owned to Animal Science Department. All trials developed in this study used a feedlot system, where animals were kept in individual pen. Forty Ile de France lambs male non-castrated were used in in vivo trial. To obtain rumen fluid, that was used in in vitro trial, four Santa Inês lambs with rumen cannula were used. The treatments evaluated were four diets: Control diet: roughage + concentrate; PM20: roughage + concentrate with peanut meal (PM) at 20% of DM; CG25: roughage + concentrate with crude glycerin (CG) at 25% of DM; and PMCG: roughage + concentrate with PM at 10% of DM and CG at 12.5% of DM. The roughage:concentrate ratio was 40:60 for all these diets. The parameters of the in vitro and in vivo experiments used were completely randomized with four treatments. When significant, the means between treatments were compared using Tukey test (P < 0.05). There was no effect of co-product inclusion on intake, except ether extract and neutral detergent fiber, which were higher for PM20 compared with CG25 diet. Apparent digestibility of dry matter (79.87%) and some nutrients (organic matter, crude protein, and neutral detergent fiber) was higher (P < 0.05) with CG25 diet. In vitro cumulative gas production was greater in CG25 and PMCG compared to the other diets, at early measurement points (2, 4, 6, and 10 h). The concentrations of methane, volatile fatty acids, and acetate:propionate ratio in vitro did not differ (P > 0.05) among diets.Discussion: Probably the high quality of the glycerin used (83.9% glycerol, 12.01% humidity, 3.79% salts, and 0.28% organic matter, no fat, as described by the manufacturer) may explain the low EE concentration observed in the diet using only crude glycerin and the observed lack of DMI effects in all diets. About apparent digestibility, the greater values measured for crude protein can be explained by superior synchronism during fermentation of the proteins and carbohydrates in the diet. The data showed that treatment CG25 obtained higher initial gas production, followed by treatment PMCG which contained 12.5% crude glycerin. Probably these results were caused by the greater apparent digestibility of DM in treatments that included crude glycerin. Our results of volatile fatty acid concentration are different from the decrease in molar proportion of acetic acid and increase of propionic acid described by several authors, with the inclusion of glycerin in the diet. However, the absence of effect by co-product inclusion on the molar proportion of acetic, propionic, and butyric acids measured in this trial reinforce the report from other authors that affirmed the same situation. Hence, the inclusion of PM at 20% of DM and CG at 25% of DM could successfully replace the traditional diets of feedlot lambs such as soybean and corn, respectively, without damages to intake and ruminal parameters in vitro.

Application of machine learning models in predicting initial gas production rate from tight gas reservoirs

Driven by advancements in technology, tight-gas field development has become a significant source of hydrocarbon to the energy industry. The amount of data generated in the process is immense as most platforms are now being digitized. Machine learning tools can be used to analyse this data in order to build patterns between several dependent and independent variables. Forecasting initial gas production rates has important implications in the planning production/processing facilities for new wells, affects investment decisions and is an important component of reporting to regulatory agencies. This study is based on the analysis of reservoir rock/fluid properties and selected well parameters to build decision-based models that can predict initial gas production rates for tight gas formations. In this study, two machine learning predictive models; Artificial Neural Network (ANN) and Generalized Linear Model (GLM), were used to determine the expected recovery rate of planned new wells. Production data was retrieved from 224 wells and used in developing the model. The results obtained from these models were then compared to the actual recorded initial gas production rate from the wells. Results from the analysis carried out revealed a Mean Square Error (MSE) of 1.57 on a GLM model whereas the ANN model gave an MSE of 1.24. Key Performance Index for the ANN model revealed that reservoir thickness had the highest (36.5%) contribution to the initial gas production rate followed by the flowback rate (29%). The reservoir/fluid properties contribution to the initial gas production rate was 53% while the hydraulic fracture parameters contribution to the initial gas production rate was 47%.

Numerical Simulation Study on Seepage Theory of a Multi-Section Fractured Horizontal Well in Shale Gas Reservoirs Based on Multi-Scale Flow Mechanisms

Aimed at the multi-scale fractures for stimulated reservoir volume (SRV)-fractured horizontal wells in shale gas reservoirs, a mathematical model of unsteady seepage is established, which considers the characteristics of a dual media of matrix and natural fractures as well as flow in the large-scale hydraulic fractures, based on a discrete-fracture model. Multi-scale flow mechanisms, such as gas desorption, the Klinkenberg effect, and gas diffusion are taken into consideration. A three-dimensional numerical model based on the finite volume method is established, which includes the construction of spatial discretization, calculation of average pressure gradient, and variable at interface, etc. Some related processing techniques, such as boundedness processing upstream and downstream of grid flow, was used to limit non-physical oscillation at large-scale hydraulic fracture interfaces. The sequential solution is performed to solve the pressure equations of matrix, natural, and large-scale hydraulic fractures. The production dynamics and pressure distribution of a multi-section fractured horizontal well in a shale gas reservoir are calculated. Results indicate that, with the increase of the Langmuir volume, the average formation pressure decreases at a slow rate. Simultaneously, the initial gas production and the contribution ratio of the desorbed gas increase. With the decrease of the pore size of the matrix, gas diffusion and the Klinkenberg effect have a greater impact on shale gas production. By changing the fracture half-length and the number of fractured sections, we observe that the production process can not only pursue the long fractures or increase the number of fractured sections, but also should optimize the parameters such as the perforation position, cluster spacing, and fracturing sequence. The stimulated reservoir volume can effectively control the shale reservoir.

Parameter determination for a numerical approach to undeveloped shale gas production estimation: The UK Bowland shale region application

The estimation of production potential provides the foundation for commercial viability appraisal of natural resources. Due to uncertainty around production assessment approaches in the unconventional petroleum production field, an appropriate production estimation methodology which address the requisite uncertainty at the planning stage is required to guide energy policy and planning. This study proposes applying the numerical unconventional production estimation method which relies on geological parameters, (pressure, porosity, permeability, compressibility, viscosity and the formation volume factor) as well as the rock extractive index (a measure of technical efficiency). This paper develops a model that estimates the appropriate values for four of these parameters based on a depth correlation matrix while a stochastic process guides two based on known data range. The developed model is integrated with a numerical model to estimate gas production potential. The developed framework is eventually applied to undeveloped shale gas wells located in the Bowland shale, central Britain. The results account for below ground uncertainty and heterogeneity of wells. A sensitivity analysis is applied to consider the relative impacts of individual parameters on production potential. The estimated daily initial gas production rate ranges from 15,000scf to 319,000scf while estimated recovery over 12 years is approximately 1.1bscf in the reference case for wells analyzed.

The reasonable development technology policy in sweet spot of tight gas reservoir

The development of sweet spot in tight gas reservoir is restricted by various factors, which cannot guarantee reasonable, efficient, and low-cost development, and technical policy of development is also immature. Through fine geological modeling and numerical simulation technology, and in accordance with the microseismic monitoring results, the pressure recovery test data, and analysis of the relationship between irreducible water saturation and permeability, history matching is conducted. On this basis, new wells can be designed and simulated again in this sweet spot. Finally, it is concluded that the horizontal well with staggered well pattern is the reasonable development of sweet spot, the reasonable well space is 600–800 m, the reasonable length of the horizontal section is 1200 m, and the reasonable initial gas production rate is 8 × 104 m3/day.

Integration of depositional, petrophysical, and petrographic facies for predicting permeability in tight gas reservoirs

Understanding the linkages between grain mineralogy and diagenetic and sedimentary processes enhances the reliability of petrophysical models to predict reservoir deliverability from permeability. Petrographic data within well-defined depositional facies reveal the diagenetic evolution of porosity-permeability relationships. Formation evaluation methods relying solely on petrophysical rock typing are seriously limited when predicting ultimate reservoir performance in complex pore structures. The Almond Formation, Wyoming, is characterized by three depositional facies associations — shoreface, deltaic (bay head and flood tide), and fluvial-coastal plain — which present three distinctive porosity-permeability trends. Textural features resulting from depositional processes, such as grain size and sorting, vary little between facies associations, yet permeability can vary by up to four orders of magnitude for the same porosity value. Differences between petrophysical facies are primarily driven by diagenetic (cementation and grain dissolution) effects on different framework grain compositions (petrographic facies). Therefore, the main difference between the facies associations is diagenetic, due to provenance and transport mechanisms. The characterization of depositional and diagenetic controls on pore geometry allows the narrowing of uncertainty in absolute permeability prediction. We have quantified the relationship between depositional facies, with their specific mineral composition and diagenetic overprint, and the steepness functions in porosity-permeability space. This analysis allowed us to effectively reduce the uncertainty in the prediction of initial gas production from wireline logs.

Qualitative modeling of multi-stage fractured horizontal well productivity in shale gas reservoir

As an important unconventional gas resource, shale gas has become an important part of gas production in recent years with the advantage of horizontal well drilling and large-scale multi-stage hydraulic fracturing completion technologies. The shale gas reservoir numerical simulation advances were reviewed and a multi-stage fractured horizontal well numerical simulation was performed to qualitatively modeling the well productivity in over-pressured shale gas reservoir based on actual shale properties and well completion parameters. A single horizontal well model was established on the basis of dual-porosity model and logarithmically spaced grid refinement. A comprehensive comparison and analysis of the initial average gas production, daily gas production, cumulative gas production, adsorbed gas and free gas cumulative production were provided to investigate the influence of matrix permeability, SRV permeability, hydraulic fracture conductivity and half length, SRV size, bottomhole pressure on the well performance. The research shows that for the high matrix permeability (Km > 10−7 mD) and low SRV permeability (KSRV < 0.01 mD), the SRV permeability has a significant impact on the initial average gas production. For the high matrix permeability (Km > 10−7 mD) and medium SRV permeability (0.01 mD < KSRV < 0.5 mD), the initial average gas production is controlled by both the matrix and SRV permeability. For the high matrix permeability (Km > 10−7 mD) and high SRV permeability (KSRV > 0.5 mD), the initial average gas production is mainly controlled by the matrix permeability. When the matrix permeability is lower than 10−9 mD, the cumulative gas production is too low to be of economic interest. For the matrix permeability (10−9 mD < Km < 10−5 mD), the matrix permeability and SRV permeability are all important factors that influence the cumulative gas production. For the matrix permeability (Km > 10−5 mD), the matrix permeability has much more impact on cumulative gas production than that of SRV permeability. The daily gas production and cumulative gas production are independent of hydraulic fracture conductivity and half length. The initial gas production of multi-stage fractured horizontal well is also independent of SRV sizes. The SRV size mainly controls the gas production decline characteristic. With the increase of the SRV size, the daily gas production declines slowly. The SRV size determines the cumulative gas production directly. With the increase of the SRV size, the cumulative gas production increases linearly. The bottomhole pressure has a significant impact on cumulative gas production. With the decrease of the bottomhole pressure, the cumulative gas production of 20 years increases linearly.

Enterobacteriaceae species during manufacturing and ripening of semi–hard and soft raw ewe’s milk cheese: Gas production capacity

The aim of this work was to identify the main species of Enterobacteriaceae present in two different varieties of raw ewe’s milk cheese, to study their evolution during manufacturing and ripening, and to assess their potential to produce gas from lactose. Enterobacteriaceae activity may influence cheese ripening; it can even be responsible for some specific characteristics of artisanal cheeses. Nevertheles some of these microorganisms are potential pathogens. Enterobacteriaceae growth and disappearance were different between the soft and the semi–hard cheese variety, as well as the proportions of the species detected. Citrobacter freundii, Citrobacter braakii and Klebsiella oxytoca were the predominant species in milk and curd, whereas Hafnia alvei was predominant throughout ripening. The highest gas production was generated by Enterobacter nimipresuralis, C. braakii and Enterobacter cloacae strains, followed by Enterobacter aerogenes, H. alvei, K. oxytoca and C. freundii strains. According to the species found, their levels during the initial ripening stages and gas production ability, C. braakii, C. freundii, K. oxytoca and H. alvei can be considered as responsible for early blowing in soft and semi–hard ewe cheeses. The identification of the Enterobacteriaceae species most likely responsible for early blowing can lead to a better understanding of raw milk cheese ripening, and therefore, to the improvement of its quality.

Hybrid combination genetic algorithm and controlled gradient method to train a neural network

Multivariate predictive analysis is a widely used tool in the petroleum industry in situations in which the deterministic nature of the relationship between a variable that requires prediction and a variable that is used for the purposes of such prediction is unknown or very complex. For example, to perform a sweet-spot analysis, it is necessary to predict potential oil and gas production rates on a map, using various geologic and geophysical attribute maps (porosity, density, seismic attributes, gravity, magnetic, etc.) and the initial oil and gas production rates of several control or training wells located in the area of interest. We have developed a new technology that allows for building a stable nonlinear predictive operator by using the combination of a neural network, a genetic algorithm, and a controlled gradient method. The main idea behind the proposed technology is to combine stochastic and deterministic approaches during the construction of the predictive operator at the training stage. The proposed technology avoids many disadvantages of the genetic algorithm and gradients methods, such as a high level of dependency on the initial values; the phenomenon of over-fitting (overtraining), which results in creation of an operator with unstable predictability; and a low speed of decreasing error during iteration, and, as a result, a low level of prediction quality. However, the above-mentioned combination uses the advantages of both methods and allows for finding a solution significantly closer to a global minimum for the objective function, compared to simple gradient methods, such as back propagation. The combination of these methods together with Tikhonov regularization allows for building stable predictions in spatial or/and time coordinates.

Factors Controlling Fluid Migration and Distribution in the Eagle Ford Shale

Summary Production of shale and tight oil is the cornerstone of the United States race for energy independence. According to the US Energy Information Administration, approximately 90% of the oil-production growth comes from six tight-oil plays. The Eagle Ford is one of these plays, and it accounts for 33% of the oil-production growth with a contribution of 1.3 million B/D. This is outstanding. However, oil recoveries as a percentage of the original oil in place (OOIP) are extremely low. This must be improved. A geological challenge in the Eagle Ford shale is the understanding of unconventional fluids distribution over geologic time: Shallower in the structure, there is black oil; deeper and to the south; condensate appears; and at the bottom, dry gas can be found. Differences in burial depth, temperature, and vitrinite reflectance are used to explain this unique distribution. A similar fluid distribution occurs in other unconventional reservoirs (e.g., Duvernay shale in Canada). The low oil recovery and the unusual distribution of fluids led to the key objective of this paper—to identify the main factors that control fluid migration (caused by buoyancy of gas in oil) from one zone to another through geologic time. This was performed by constructing a conceptual cross-sectional compositional simulation model with northwest/southeast orientation that allowed the study of fluid migration, fluid distribution, and fluid contacts throughout 1 million years while maintaining computational time within reasonable limits. The controlling parameters studied were porosity, permeability, pore-throat aperture (rp35), and spacing between natural fractures. Results show that fluids in the matrix remained with approximately the same original distribution (i.e., approximately the same dry-gas/condensate contact and approximately the same condensate/oil contact). These fluids are the target of an ongoing research project with the ultimate goal of improving oil recovery from tight reservoirs by means of enhanced oil recovery (EOR) (Fragoso et al. 2015). There is, however, some gas migration through natural fractures to the top of the structure. This migration is interpreted in this study to be responsible for higher initial gas production in some oil wells in the top of the structure. Some operators indicate, however, that rapid gas/oil-ratio increases in the updip oil region are the result of low reservoir pressures and the rapid onset of two-phase flow. It would probably take geochemical evidence to support this conclusion.

Establishment and application of a remote automatic control platform for CBM production

Remote data monitoring has been applied in the production of CBM wells. It is necessary to realize remote regulating and automatic control on production systems of CBM wells as soon as possible, so that production cost can be reduced effectively and fine production of CBM wells can be improved. In this paper, remote production control technologies were designed based on production behaviors of CBM wells. And then, in light of the features of automatic monitoring instruments, automatic production of CBM wells was divided into four stages (i.e. before casing pressure occurring, casing pressure building, initial gas production and gas production). Finally, an automatic control program was developed and embedded into on-site control terminals after study was carried out on automatic control logics and methods of each production stage of CBM wells. It is for the first time that gas and water production of CBM wells are automatically regulated precisely and automatic CBM production modes are adopted with the linkage control of gas and water production. Based on this production network and remote control platform system, terminal operation is controlled and feedback according to the production orders which are set and delivered remotely. In this way, CBM well production is automatically controlled over long distance. Practical operation results in the Hancheng area, Shaanxi, shows that establishment and application of this automatic control platform contribute to the improvement of fine production of CBM wells and their continuous and stable production.

Reservoir characterization in an underground gas storage field using joint inversion of flow and geodetic data

SummaryCharacterization of reservoir properties like porosity and permeability in reservoir models typically relies on history matching of production data, well pressure data, and possibly other fluid‐dynamical data. Calibrated (history‐matched) reservoir models are then used for forecasting production and designing effective strategies for improved oil and gas recovery. Here, we perform assimilation of both flow and deformation data for joint inversion of reservoir properties. Given the coupled nature of subsurface flow and deformation processes, joint inversion requires efficient simulation tools of coupled reservoir flow and mechanical deformation. We apply our coupled simulation tool to a real underground gas storage field in Italy. We simulate the initial gas production period and several decades of seasonal natural gas storage and production. We perform a probabilistic estimation of rock properties by joint inversion of ground deformation data from geodetic measurements and fluid flow data from wells. Using an efficient implementation of the ensemble smoother as the estimator and our coupled multiphase flow and geomechanics simulator as the forward model, we show that incorporating deformation data leads to a significant reduction of uncertainty in the prior distributions of rock properties such as porosity, permeability, and pore compressibility. Copyright © 2015 John Wiley & Sons, Ltd.

Early prediction of Biochemical Methane Potential through statistical and kinetic modelling of initial gas production

A major drawback of Biochemical Methane Potential (BMP) tests is their long test duration, which could be reduced substantially if the final gas production could be predicted at an earlier stage. For this purpose, this study evaluates 61 different algorithms for their capability to predict the final BMP and required degradation time based on data from 138 BMP tests of various substrate types. By combining the best algorithms it was possible to predict the BMP with a relative root mean squared error (rRMSE) of less than 10% just 6days after initiation of the experiment. The results from this study indicate that there is a possibility to shorten the test length substantially by combining laboratory tests and intelligent prediction algorithms. Shorter test duration may widen the possible applications for BMP tests in full-scale biogas plants, allowing for a better selection and proper pricing of biomass.

Experiments on the gas production of brown coal degraded by exogenous methanogens

To investigate the ability of exogenous bacteria to degrade brown coal, methanogens were enriched from anaerobic sludge and domesticated using brown coal as carbon source. After domestication, the lag time of initial gas production is shortened from 12 to 6 days and the CH4 production increased by 29.2% in 30 days. The generated biogas is composed of CH4 and a little CO2, no heavy hydrocarbons are detected. Experiments on gas production influencing factors demonstrate that the best initial pH for the culture medium is 7.0 and the maximum gas production is 1.9 times and 2.4 times higher than that at pH 6.4 and pH 7.4, respectively. The particle size of coal is one of factors influencing the gas production: the general trend is the smaller the particle size, the bigger the gas production, but the variation of gas production is not significant with decreasing particle size. Gas produced by the culture medium accounts for around 50% of the total gas production and it is likely caused by the addition of L-cysteine (0.5 g/L) and yeast extract (1 g/L) to the medium.

Optimal Well Design for Enhanced Stimulation Fluids Recovery and Flowback Treatment in the Marcellus Shale Gas Development using Integrated Technologies

A typical well was designed with formation properties in Springfield Township, Bradford County, Pennsylvania using computer modeling group (CMG) software to analyze the production potential in the area over 40 years. Multilateral wells gave the highest initial gas production rate and cumulative production of 1.18E+07 ft3/day and 2.6E+10 ft3 respectively. FracPro® software was used for the fracture design. The simulation demonstrates that hydraulic fracturing can appreciably increase cumulative production and production rate in the well, with an estimated 3.6 Million gallons (of water) per well required to fracture open the formation for the free flow of gas. Due to the efficient well design and stimulation design, a load recovery of approximately 86% of the injected fluid is achievable which amount to 73,714 bbls of waste water to be treated per stimulation job. The system capacity of the forward osmosis integrated process, operating on hydraulic fracturing flow-back water will treat 604,800 gallons per day (gal/d). The novel design takes into consideration the flow-back recovery per hour in the system, which is 600 bbl/ hr for the centralized system, but 150 bbl/hr for a single well pad. The tank size required would be a 25,000 gallon tank, covering approximately 1,202 square feet and cost $52,255. The forward osmosis (FO) system uses a thin-film composite (TFC) membrane system based on efficiency and power generation capabilities. The capital cost of each system is about $100,000. The annual operating cost of the FO system would be about $ 0.60/kgal of produced water. A cost estimate savings of over one million dollars ($1,000,000) is expected if the integrated forward osmosis system is implemented. Aside cost savings, the emission generated from the system is minimal, which makes it considerably environmentally friendly compared to other types of treatments.

Heat and pH Stability of Alkali‐Extractable Corn Arabinoxylan and Its Xylanase‐Hydrolyzate and Their Viscosity Behavior

In in vitro batch fermentations, both alkali-extractable corn arabinoxylan (CAX) and its xylanase-hydrolyzate (CH) were utilized by human fecal microbiota and produced similar short chain fatty acid (SCFA) contents and desirable long fermentation profiles with low initial gas production. Fortification of these arabinoxylans into processed foods would contribute desirable dietary fiber benefits to humans. Heat and pH stability, as well as viscosity behavior of CAX and CH were investigated. Size exclusion chromatography was used to analyze the molecular size distribution after treatment at different pH's and heating temperatures for different time periods. Treated under boiling and pressure cooking conditions at pH 3, CAX was degraded to a smaller molecular size, whereas the molecular size of the CH showed only a minor decrease. CAX and CH were mostly stable at neutral pH, except when CAX was treated under pressure for 60 min that slightly lowered molecular size. At 37 °C, neither CAX nor CH was adversely affected by treatment at low or neutral pH. The viscosities of solutions containing 5% and 10% of CAX were 48.7 and 637.0 mPa.s, respectively that were higher than those of solutions containing 5% and 10% of its hydrolyzate at shear rate 1 s⁻¹. The CAX solutions showed Newtonian flow behavior, whereas shear-thinning behavior was observed in CH solutions. In conclusion, the hydrolyzate of CAX has potential to be used in high fiber drinks due to its favorable fermentation properties, higher pH and heat stability, lower and shear-thinning viscosity, and lighter color than the native CAX. Arabinoxylan extracted by an alkali from corn bran is a soluble fiber with a desirable low initial and extended fermentation property. Corn arabinoxylan hydrolyzate using an endoxylanase was much more stable at different levels of acidity and heat than the native arabinoxylan, and showed lower solution viscosity and shear-thinning property that indicates its potential as an alternative functional dietary fiber for the beverage industry.

Achieving Solids-Free Gas-Production Target Rate From Highly-Unconsolidated-Sandstone Formation Intervals

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 141878, ’Achieving Target Solids-Free Gas Rate From Highly- Unconsolidated-Sandstone Formation Intervals,’ by Nahr Abulhamayel, J. Ricardo Solares, SPE, Walter Nunez, Ataur Malik, SPE, Mustafa Basri, SPE, and Andrew McWilliams, Saudi Aramco, and Oumer Tahir, SPE, and Mohammad Abduldayem, SPE, Weatherford, prepared for the 2011 SPE Middle East Oil and Gas Show and Conference, Manama, Bahrain, 20-23 March. The paper has not been peer reviewed. One of the most challenging aspects of producing wells drilled in the unconsolidated pre-Khuff gas reservoirs in Saudi Arabia is to achieve solids-free production while trying to achieve high gas rates. Challenging reservoir conditions include high temperature and pressure, high stress, heterogeneity, and the absence of stress barriers that together make placing fracture treatments very difficult. Stand-alone screens were installed in openhole well completions in the sandstone reservoir and achieved excellent results by eliminating the need for a fracturing treatment. Introduction Achieving solids-free production from unconsolidated-sandstone reservoirs is an ongoing challenge. The importance of effective sand control in these wells is the need to maintain the integrity of bottomhole and surface processing equipment and facilities, and to ensure that production targets are met consistently. Fig. 1 shows examples of the potential damage that sand production can cause. Several approaches including indirect hydraulic-fracturing stimulation, high-angle and increased-contact wells, and, more recently, sand-screen completions have been used to develop these gas reserves. Among these approaches, the sand-screen completions, in both vertical and high-angle wells, was field tested in two wells, and then it was implemented in more wells after the success of the pilot. Formation Geology The sandstone formation in which the two well pilot tests were conducted is a siliciclastic formation in the pre-Khuff stratigraphic section in Saudi Arabia. Gas resources are in sandstones of variable quality within a sequence of sandstones, siltstones, mudstones, and shales. Because the formation was deposited in a shallow marine tidally influenced shoreline setting, it is heterogeneous in character. Heterogeneity imposes both vertical- and lateral-distribution variability of reservoir-quality properties over a wide range of scale and geometry. Reservoir quality in this sandstone formation is a function of several factors, particularly grain size and sorting and clay type and content, which are controlled largely by the primary sedimentological process. Sandstone cementation and diagenesis-controlled cementation also play a role. These reservoir-quality-influencing factors are, in turn, subject to sedimentological and diagenetic processes, controlled largely by the depositional setting. Porosity and permeability of the gas-bearing intervals vary over a wide range. The well-plan metric for the initial gas-production rate from the formation is from 15 to 20 MMscf/D. Although this rate is achievable, given the permeability and pressure characteristics of the reservoir, the formation’s unconsolidated nature increases the risk of exposing equipment to damaging sand production.

Channel Fracturing - Paradigm Shift in Tight Gas Stimulation

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 140549, ’Channel Fracturing - A Paradigm Shift in Tight Gas Stimulation,’ by J. Johnson, SPE, M. Turner, SPE, and C. Weinstock, SPE, Encana; and A. Pena, SPE, M. Laggan, SPE, J. Rondon, and K. Lyapunov, Schlumberger, prepared for the 2011 SPE Hydraulic Fracturing Technology Conference and Exhibition, The Woodlands, Texas, 24-26 January. The paper has not been peer reviewed. The hydraulic-channel-fracturing technique relies on the engineered creation of a network of open channels within the proppant pack, providing highly conductive paths for fluid flowing from the reservoir to the wellbore. The Lance formation in the Jonah field near Pinedale, Wyoming, was selected for this study. Results indicate that implementation of the channel-fracturing technique increased initial gas production and estimated recovery over conventional fracturing methods. Positive features during this campaign included reduced net-pressure-increase estimates from pre- and post-fracture-treatment shut-in-pressure measurements, reduced tendency for vertical fracture growth, and elimination of near-wellbore screenouts. Introduction Natural gas plays a major role in the assortment of energy resources that sustain the USA. The imbalance between future energy demands and reduced availability of gas from conventional sources dictates the need to increase gas recovery from unconventional sources such as tight gas reservoirs, shale-gas reservoirs, and coal seams. Hydraulic-fracturing treatments in tight gas formations during the 1970s consisted of pumping large quantities of a propping agent and carrying gelled fluids and emulsions at pressures in excess of the formation-fracturing pressure. Beginning in the 1980s, this fracturing technique included various combinations of nitrogen gas and/or liquid carbon dioxide pumped in combination with fluid and proppant for stimulation purposes. Low-viscosity slickwater treatments, in which proppant is pumped at low concentrations within a high-rate water stream, became popular in the 1990s for stimulating tight gas reservoirs. All these techniques rely on filling the fracture with the propping agent to maintain an open fracture. The proppant pack placed within the fracture also serves as a conductive medium for gas flow to reach the wellbore. The effective area of the fracture covered by proppant varies according to the technique used. Typically, completion efficiency is low for slickwater treatments, and it often improves with the use of viscous carrying fluids and fibers, among other methods.