bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Application of the Isogeometric Analysis Method to Reservoir Simulation
Authors: Lynd Eric A. , Foster John T. , Nguyen Quoc P. 
Published: April 2016

Abstract
The isogeometric analysis method (IGA) has been an emerging technique for exact geometrical discretization and efficient high order approximations in the field of computational engineering. While its potential has been demonstrated in a variety of disciplines, it has yet to be applied extensively to the field of reservoir simulation. This work shows IGA's potential as a useful tool for next generation reservoir simulation, highlighting its ability to exactly capture complex-shaped geometrical features in the reservoir and, consequentially, accurately model the pressure fields. First, an IGA code is validated against the analytic solution for a quarter five-spot pattern as well as a reference solution for a straight line source problem with pressure enforced at the corners of the domain. Next, the numerical efficiency of IGA is compared against a finite element method solution of single phase flow in a 2D representative reservoir containing a centralized "S-shaped" line source. Results suggest a clear advantage of the IGA method over the classical finite element method, which has lower convergence rates in terms of number of degrees of freedom.
Coupling of Darcy's Equation with Molecular Transport and its Application to Upscaling Kerogen Permeability
Authors: Kou Rui , Alafnan Saad Fahaid , Akkutlu I. Yucel 
Published: April 2016

Abstract
Quantification of gas transport in organic rich shale is important in determining natural gas production rates. However, laboratory measurements are challenging due to very tight nature of the rock, and have large uncertainties due to presence of multiple mechanisms of gas transport at multiple pore scales. In this paper, the emphasis is on the understanding of transport inside organic material known as kerogen and prediction of its permeability.
We performed nonequilibrium molecular dynamics simulations of steady-state methane flow in single-wall carbon nanotube based on a moving piston model (Riewchotisakul and Akkutlu, 2015). The piston model allows us to observe transition from convection to molecular (pore) diffusion under the reservoir conditions and to understand the effects of adsorbed methane molecules on the overall transport in the tube. The results show that the adsorbed molecules are not only mobile but also contribute a significant portion to the total mass flux. Simulations with different sizes of capillaries show that the contribution is profound in capillaries with diameter less than 10nm. The adsorbed-phase transport velocity is independent of capillary size, but strongly dependent on pressure drop across the capillary. This allowed us to formulate the transport as an additional diffusion mechanism by the capillary walls using a modified Hagen-Poiseuille equation and predict the transport enhancement.
In the second part of the paper, we considered steady-state transport across a pore-network of inter-connected nano-capillaries. The preliminary simulation results show that the modified Hagen-Poiseuille equation leads to representative elementary volume of a model kerogen. The estimated permeability of the volume is sensitive to surface properties of the nanocapillary walls indicating that fluid-wall interactions driven by molecular forces could be significant during the large-scale transport within kerogen. A modified Kozeny-Carmen correlation is proposed.
The Impact of Rock Properties on Acid Jetting in Carbonate Rocks: An Experimental Study
Authors: Ndonhong V. , Belostrino E. , Zhu D. , Hill A. D. , Beckham R. E. , Shuchart C. E. 
Published: April 2016

Abstract
Acid jetting, as a well stimulation method for carbonate reservoirs, has shown optimistic results in the production enhancement of some extended reach horizontal wells. It was used initially to promote damage removal along a wellbore via multiple strategically-located injection nozzles. It has the potential to place the injecting fluid at the locations that need stimulation. Jetting may also enhance wormhole propagation compared with conventional matrix acidizing. These hypotheses are currently being investigated to improve the design for more efficient stimulation treatments.
We have conducted an experimental study to investigate the effect of jetting on wormhole efficiency. The jetting experiments are conducted at a constant pressure with linear core-flood tests, where a stand-off distance is maintained between the injection nozzle tip and the core. At low-velocity acid injection, jetting effectively removes mud filter-cake by mechanical actions. Jetting also creates wormholes in carbonate cores. The combination of mechanical and chemical reactions stimulates carbonate rocks better than matrix acidizing without the jetting nozzle. When the jetting velocity increases, the dissolution pattern changes. An isolated locally compact dissolution results in a cavity at the entries of core samples by jetting, followed by a wormhole structure. With the known dissolution pattern, sensitivity studies are carried out to investigate the effect of various parameters on the experimental outcome.
We used Indiana and Winterset limestone rocks in the experiments. 15% HCl (by weight) at ambient temperature was used and the core dimensions were 4 inches in diameter and 16 inches in length. Various combinations of acid jetting velocities and acid fluxes were considered. The Winterset limestone cores are more heterogeneous, with higher porosity and lower permeability than the Indiana limestone cores. From the experimental results, the results of acid jetting from the two different rock samples are compared.
The experimental results indicate that acid jetting follows the same trend as matrix acidizing regarding wormhole propagation once cavities are created. Jetting velocity and acid flux are the critical parameters in jetting design for optimal stimulation results. Acid jetting tends to create different dissolution patterns for Indiana limestone and Winterset limestone cores. The observations from this work highlight the importance of understanding the dynamic chemical process of jetting in the design of successful acid stimulation jobs.
Comparative Study of Acid Fracturing and Propped Hydraulic Fracturing for a Tight Carbonate Formation
Authors: Suleimenova A. , Wang X. , Zhu D. , Hill A. D. 
Published: April 2016

Abstract
Acid fracturing is one of the methods for well stimulation in carbonate formations. Compared to propped hydraulic fracturing, acid fracturing takes a simpler procedure, and therefore, usually with a lower cost. On the other hand, fracture conductivity is more difficult to maintain, especially in formations that have high closure stress. In this study, a procedure is developed to evaluate the feasibility of acid fracturing by comparing conductivity generated from an unpropped fracture, a propped fracture and acid fracture. The target formation features extreme closure stress and low permeability at a depth of 5000-7000 meters. The efficiency of acid fracturing is challenged by the severe condition of the formation.
The laboratory experiments were performed using the core samples from three wells from the productive interval of the target reservoir. The acid fracturing treatment conditions that have been used in the field were simulated during the laboratory experiments. The fracture conductivity was measured for un-propped, acid-etched, and propped fractures at different closure stresses using an apparatus consisting of a modified API conductivity cell and a load frame The fracture face surface of the intact and acidized core samples was scanned with a profilometer to characterize the change in surface profile to calculate the volume of dissolved rock caused by acid etching, and the initial fracture conductivity under zero closure stress. Conductivity decline as a function of closure stress was recorded and examined during the study.
The results of the comparative study on fracture conductivities showed that the final propped fracture conductivity was higher than the acid fracture conductivity for all of the core samples. Also, the rate of conductivity decline with increasing closure stress was lower for the propped fracture conductivity compared to the acid fracture conductivity. The conclusion was made that the propped hydraulic fractures would retain a greater conductivity under the formation closure stress compared to the acid fractures. Hence, the hydraulic fracturing with proppant would be a more effective stimulation treatment compared to the acid fracturing for improving the wells productivity for the studied reservoir.
Case Study of a Super-Giant Field Rejuvenation
Authors: Li Yong , Li Baozhu , Liu Lang , Xiong Lihui , Luo Hong , Peng Hui , Wang Daigang 
Published: April 2016

Abstract
Many oilfields in the world are mature and developed at the later stages of their life, and how to rehabilitate these fields is the biggest challenging problem. This paper presents an integrated approach with multi-disciplines to rejuvenate one of the world's super-giant oilfields in Middle East.
The K super-giant oilfield have more than 60 years' production history. Current oil recovery of the field is over 50% with more than 60% prolonged shut-in wells, and higher than 10% annual decline rate. The proposed integrated rejuvenation approach involved the analysis of comprehensive multi-disciplines, from geology and reservoir engineering understanding, to completion, stimulation, and surface facilities analysis. And based on the analysis results, shut-in wells are ranked into different types respectively, different treatments are applied according to well rank. Production rate of producing wells are optimized based on integrated models. New well candidates and other well work are also proposed.
For K oilfield, prolonged shut-in wells are classified into 4 ranks by principal component analysis, which mainly based on the understanding from bottom hole pressure evaluation, remaining oil description, offset well performance analysis, status of surface facilities, etc. Wells of rank 1 can be potentially open blowing directly with oil rate higher than 3000 mbd, and wells of rank 2 need install new ESP for artificial lift with oil rate only between 2000 mbd and 3000 mbd. While wells of rank 3 have much surface facilities problems and much lower potential oil rate, and wells of rank 4 have no potential to re-open. Also, an integrated model with subsurface, wellbore and surface facilities combined are established for production optimization. Based on the model, performance of producing wells can be analyzed, and flowing path or linkage pipeline of some wells were changed in order to meet the potential capacity of the well and surface facilities. Infilling well candidates are selected through pressure and remaining oil distribution analysis, which are mainly placed at the crest areas. Furthermore, other well works such as re-perforating, sidetracking, are also implemented with successful results.
This study details a successful application of an integrated field rejuvenation approach for a super-giant field, which stabilized the production of the field at the first year and made a 10% production rate increment for the second year. Most importantly, the methodology presented can be adopted in other similar mature fields.
Channel Fracturing Technology Provides an Effective Solution to Unlock Tight Gas Development and Production Potential in Saudi Arabia
Authors: Rahim Zillur , Al-Kanaan Adnan , Kayumov Rifat , Al-Jalal Ziad , Fredd Chris 
Published: April 2016

Abstract
Economic recovery and production of non-associated gas from the tight clastic reservoirs in Saudi Arabia faces some challenges resulting from high bottomhole temperature, high in-situ stress, low permeability, and high Young's modulus and rock compressive strength. Hydraulic fracturing, a necessary means to exploit the tight reservoirs, encounters constrains such as high fracture initiation and treating pressure, risk of pre-mature screen-out, and conductivity degradation with time. A conventional fracturing treatment in such challenging environment necessitates increased polymer loading in fracturing fluids to stabilize fluid viscosity and using smaller size proppant at low concentrations to ensure proppant placement. This results in shorter effective fracture half-length and low fracture conductivity. Reduced contact area decreases production potential. Additionally, high polymer loading is not easily breakable and may create major damage to the proppant pack, thereby substantially reducing fracture conductivity. The challenges compound when the reservoir is relatively tight and often cannot generate enough energy to clean up the injected fracturing fluids. To overcome these challenges, channel fracturing was introduced where proppants are added in pulses in fracturing fluids along with dissolvable fibers creating stacks of pillar-like structure inside the fracture. These proppant pillars stay suspended and are held by the fibers during the treatment. Once the pumping is stopped, the fracture closes on the pillars and the fibers degrade under formation temperature. These pillars hold the fracture open and act as columns; the void surrounding them are essentially stable channels along the entire geometry of the fracture that provide open pathway for hydrocarbons to flow in a near-infinite conductivity environment. The technology also reduces the amount of proppant pumped compared to a conventional treatment, and pulsation of proppant during pumping reduces the risk of an early screen-out.
Upscaling WFT Permeability Data: A Systematic Approach to Analyzing and Integrating Well Test Data From Wireline Formation Testers WFT
Authors: Mkhize S. , Aluko A. O. , Gringarten A. C. 
Published: April 2016

Abstract
Permeability is a rock property which measures the ability of a porous medium to transmit fluids and controls the fluid flow direction and rates. Permeability can be obtained from cores, wireline formation tests (WFT), nuclear magnetic resonance (NMR) logs and well tests.
Typical usages of WFT include measuring formation pressures along the wellbore, taking fluid samples, identifying fluid types and evaluating reservoir structure. Occasionally, WFT is used to replace a drill stem test (DST) in an exploration well. As in well tests, WFT data are measured in situ but, whereas well tests provide an average over a larger formation volume, WFT permeabilities are generally associated with a smaller volume of investigation around the measurement depth. A limitation of pressure transient analyses with WFT, however, is that they often only yield spherical permeabilities, due to short radii of investigation resulting from small rates and short pretest durations. In such a case, anisotropy can be obtained from formation rate analysis (FRA). Pressure transients generated during fluid sampling by WFT tools can have longer radii of investigation and reach radial flow.
In this study, pressure transient analysis (PTA) and FRA techniques are applied first to model generated WFT data, then to an actual gas reservoir using invaded zone and formation fluid properties. PTA derived spherical permeabilities and FRA results are then combined to obtain permeability anisotropy and estimate both horizontal and vertical permeabilities versus depth. These are then upscaled to compare with permeabilities obtained from DST’s.
Various upscaling methods were investigated. It was found that (1) weighted arithmetic average upscaling yields the best results for horizontal permeability (within 20% of DST permeabilities), and (2) harmonic averaging of vertical permeabilities gives the best match over a wide range of anisotropy values.
This study confirms that upscaled WFT permeabilities are representative of the formation permeabilities, provided appropriate upscaling methods and fluid properties representative of the test zone are used in the WFT analysis.
Biodegradation Of Hydrocarbons As A Mechanism Of Microbial Enhanced Oil Recovery
Authors: Uzukwu Chukwuemeka , Dionisi Davide 
Published: April 2016

Abstract
Microbial enhanced oil recovery (MEOR) is one of the enhanced oil recovery (EOR) techniques that is applied to oil reservoirs after primary and secondary recovery techniques to increase oil production. The successful implementation of MEOR involves an interdisciplinary approach. This paper has focused on one of such approaches which is the bioengineering aspect of MEOR that is concerned with the quantitative description of microbial growth and yield factors. Early MEOR works have focussed on the use of external carbon sources i.e. carbohydrate nutrients to produce metabolites useful for oil recovery, using the petroleum hydrocarbons present in the reservoir as the carbon source for microorganisms can be essential in microbial enhanced oil recovery as this addresses some logistic problems encountered in adverse environment. The metabolites which are useful in MEOR techniques for oil recovery can be produced by growing the microorganisms on petroleum hydrocarbons. The microbial degradation of n-alkanes and some readily biodegradable substrate has been studied. A simple respirometric method has been developed to assess the biodegradability of these compounds. Initial experiments have been performed in small-scale laboratory bioreactors to determine hydrocarbon degradation rates through oxygen consumption data (under aerobic conditions) collected over a period of time. Analysis of initial kinetic parameters has shown that estimates of hydrocarbon biodegradation based on respirometry is very reproducible with some consistency in the data generated. It has been shown from calculated microbial growth rates that petroleum hydrocarbons can be utilized under aerobic conditions at reasonably rates. The biodegradation of petroleum hydrocarbons using nitrate as electron under anoxic conditions has also been studied.
Shale Reserve Forecasting - Model Consistency and Uncertainty
Authors: Whitson Curtis Hays , Coll Carolina , Dahouk Mohamad Majzoub , Juell Aleksander Oma 
Published: April 2016

Abstract
Three general categories of modeling are traditionally used to provide shale reserve forecasting – (1) decline curve analysis (DCA), (2) rate-time analysis (RTA), and (3) numerical model history matching (HM). The focus of this paper is aligning each of the three modeling approaches to ensure maximum consistency in terms of fundamental reservoir description, including (but not limited to) initial fluid in place, reservoir rock properties, PVT, well completion factors, fracture area and conductivity, well controls, and definition of infinite-acting and boundary-dominated flow regimes. The HM model approach, though more rigorous, is time consuming and cannot be used for the hundreds of wells in a typical shale field. We recommend, as have others, that history-matched numerical models be used to help calibrate RTA and DCA models in a consistent manner for all wells.
Once a consistent model framework is achieved, reserve forecasting can be better understood by regulators, engineering and reserve teams within the operating company and their partners. Furthermore, a consistent modeling framework can provide more reliable uncertainty analysis to establish probabilistic reserves estimates in terms of P90-P50-P10 values (1P-2P-3P).
Modeling methods used in forecasting shale reserves are based on production data that includes rates and pressures. DCA applies the boundary-dominated methods such as Arps, where multiple time regions are used to capture infinite-acting and boundary-dominated flow. RTA uses dimensionless pressure and rate solutions applicable to horizontal wells with multiple fractures, including superposition, pseudopressure and pseudotime. Numerical models solve the complex set of differential equations describing multiphase fluid flow using a properly-selected grid refinement (e.g. near fractures) and, in some cases, a dual porosity/dual permeability treatment of fracture-matrix interaction.
Mechanical Degradation of Polymers During Injection, Reservoir Propagation and Production - Field Test Results 8 TH Reservoir, Austria
Authors: Puls Christoph , Clemens Torsten , Sledz Christoph , Kadnar Rainer , Gumpenberger Thomas 
Published: April 2016

Abstract
The polymer pilot test performed in the 8 TH sandstone reservoir in Austria shows incremental oil production. Soon after increasing oil cuts were detected, polymer was back-produced from the wells which were showing the oil production response. The polymer concentration increased to about 100 ppm in the back-produced water.
Size Exclusion Chromatography was used to determine the molecular weight distribution of the back-produced high molecular weight polymers (HPAM). The results showed that careful sampling is required to avoid degradation of polymers during the sampling procedure. Analyzing pressurized samples revealed that some degradation of polymers from the original average molecular weight of 20 MDa to 8 MDa occurred.
To investigate where in the surface facility-injection-reservoir-production system degradation took place, specific field tests and laboratory experiments were performed.
Chemical and biological degradation was excluded as reservoir conditions are benign (50 °C, 20,000 ppm) and nitrogen blanketing and biocides are used.
At the surface facilities, no degradation was detected. Swabbing and laboratory experiments showed that severe mechanical degradation occurs in injection wells if injection is performed under matrix injection conditions owing to high flow velocities in the near-wellbore. However, induces fractures are substantially decreasing mechanical degradation. To avoid severe degradation of HPAM, the flow velocities in the near-wellbore and related mechanical degradation have to be evaluated and the injection designed accordingly.
In the reservoir, polymers are not degraded as the flow velocities are low.
Sucker Rod Pumps as used in the production wells in the polymer pilot area do not lead to polymer degradation. This means surface polymer samples can be taken to investigate the degradation in the injection well.
Surface sampling has to be performed pressurized to avoid high shear rates and oxygen in the samples.
Integrated Development of Europe's Largest Open-Access Underground Gas Storage by Use of a Multidisciplinary Simulator
Authors: Bruijnen Pieter , Plug Willem-Jan , van Yperen Guido , Botermans Wouter 
Published: April 2016

Abstract
Between 2007 and 2014, TAQA Energy converted the Bergermeer field from a depleted gas field into a gas storage with a working volume of 4.1 billion normal cubic meter (BCM) and a production capacity of over 57 million Nm3/day from 14 wells. During this project, with a CAPEX of more than 800 million Euro (excluding cushion gas and transportation commitments), a tight planning schedule was followed. The schedule required full integration of technical, commercial and economic disciplines and had to follow an operational plan to ensure that the project would be realised on time. In order to deliver the entire system, according to technical specifications and commercial requirements, a pragmatic in-house simulator was developed: GRIP (Gas Re-Injection and Production). The tool is based on nodal analysis and uses the key parameters that would determine the performance of the storage elements. After running multiple realisations an optimum design of the gas storage was selected. During the define, execution and operation stages of the Bergermeer storage, GRIP was also used for further optimisation, forecasting and monitoring of the actual performance. The results show that the tool has been very successful in predicting the storage operational envelope, and that integration between disciplines is the key to the success.