bluuebunny/crossref_metadata_2025_split huggingface dataset:
Approximate Analytical Pressure Studies on Dual Porosity Reservoirs with Stress-sensitive Permeability
Authors: Wang Shuhua , Ma Mingxu , Lin Menglu , Chen Shengnan 
Published: May 2015

Abstract
Pressure transient analysis in porous media is commonly studied by assuming constant reservoir permeability over an entire range of formation pressure. Such assumption may not be applicable to natural fractured reservoirs where fracture permeability reduces during production. At present, there are still lacks of analytical pressure transient studies on dual porosity reservoirs with stress-sensitive permeability of the natural fractures.
An approximate analytical model was proposed in this work to investigate the pressure transient in the naturally fractured reservoirs. It was assumed that only fracture permeability was stress-sensitive, which was a function of a permeability modulus and pressure differences. The permeability function was substituted into the cylindrical pressure diffusion equation to calculate pressure distribution in the reservoir. The obtained non-linear equations were linearized by a transformation equation, and then simplified by a zero-order perturbation technique. Finally, two inner boundary conditions and three outer boundary conditions were applied, and total 6 solutions in the Laplace space were presented.
Calculated pressures from the models with and without stress-sensitive permeability were compared. It was found that the stress-sensitive solutions can be obtained by integrating the solutions from constant permeability models with the permeability modulus. For an infinite reservoir with constant flow rate boundary condition, if permeability modulus is 0.1, dimensionless pressure difference at the well bottomhole from the model with fracture permeability sensitivity is 48% higher than that of the constant fracture permeability model at later production time. Such difference can be as high as 122% if permeability modulus increases to 0.15. For locations further away from the wellbore (e.g., 12.7 m), the required pressure difference for the two models are close to each other. Finally, the exchange flow rates from reservoir matrix to natural fractures were calculated to identify different flow regimes. The proposed model not only provides an analytical and quantitative method to investigate the effects of fracture permeability-sensitivity on reservoir pressure distribution, it can also be applied to buildup analysis of well test data from stress-sensitive formations.
Challenges in Water Management of Producing Field A Case Study
Authors: Tiwari Brajesh Kumar , Al-Azmi Ali Abdullah 
Published: May 2015

Abstract
Oil fields with aquifer or with water injection support is considered to yield more in terms of oil recovery. But this water which helps in maintaining the reservoir pressure and improves the sweep, causes serious problem in oil fields in operational, environmental and economic front. There is no unique solution to improve recovery with reduced water so it is prudent to strike and balance between the water production and manage the produced water.
Umm Gudair Field, a prolific oil producer of WK, is under final development stage. Minagish Oolite limestone is the main reservoir and is producing nearly 225,000 BOPD under bottom water drive mechanism. The current reservoir pressure is sub-hydrostatic and sustained production is maintained by electrical submersible pumps (ESP). High pressure drawdown resulted in increase in water production. Hence, water conformance became important in early stage of field production. Efforts were made to manage water production by maintaining a balance between Oil Water-Contact and bottom perforation keeping a good stand off. Use of polymer, conventional cement squeeze and temporary isolation of lower layers are other methods adopted for water control. Minagish Oolite, a reservoir with good vertical communication did not respond effectively to these options and water cut kept on increasing. The conditions of left over or uneven sweep were also observed in lower layers. Historical performance suggested for systematic perforation and production approach highlighting the need for a solid surface and subsurface water management plan.
This paper deals with the challenges and steps to mitigate the produced water management in Umm Gudair Field. A holistic approach for monitoring and surveillance plan for wells with periodic review of current condition is adopted keeping cost effectiveness as an important parameter. The current water management plans with past experiences are very much in line to meet the present and future challenges.
A Simulation Investigation into the Influence of Thermophysical Fluid Properties on CO2 Brine Core Flooding Experiments
Authors: Zhou Zhaocong , Krevor Samuel , Reynolds Catriona 
Published: May 2015

Abstract
We used conventional numerical simulation of immiscible multiphase flow to reproduce laboratory observations of the CO2/Brine system. A model of homogeneous rock properties was QC'ed on Buckley-Leverett, gravity effect and capillary end effect. The natural rock heterogeneity in the core was modelled by capillary heterogeneity, and calibrated by fluid distribution observed during the experiment. The calibrated model was then used to produce synthetic relative permeability observables by changing thermophysical fluid properties, knowing what the intrinsic relative permeabilities are. It was discovered that a change in reservoir conditions and particularly CO2 viscosity can lead to changing the impact that a natural rock heterogeneity in the core has on the fluid distribution. We showed that viscous-pressure-drive determines the extent to which rock heterogeneity matters in a core flooding experiment and demonstrated that heterogeneity can lead to a deviation in observed relative permeability from its intrinsic value. Given CO2 viscosity changes much more dramatically with reservoir conditions than other fluids, the impact of reservoir conditions on relative permeability tests is apparently observed because the changing conditions increases or decreases the role of heterogeneity in the core. We therefore concluded that appropriate relative permeability observations require a homogeneous fluid distribution and thus flow rates should be used where possible to minimize the impact of heterogeneity.
The Combined Effect of Permeability and Pore Structure on Carbonate Matrix Acidizing
Authors: Etten J. , Zhu D. , Hill A. D. 
Published: May 2015

Abstract
Determination of optimal acidizing conditions through laboratory experimental study is crucial for designing matrix acid stimulation jobs in the field. Optimal interstitial velocity, vi-opt (the velocity of injected fluid that yields the minimum volume of acid needed to propagate wormholes) can be determined though curve fitting of experimental data. This optimal interstitial velocity coincides with the minimum volume of acid required for wormhole breakthrough, and therefore, the most efficient stimulation design. Optimal interstitial velocity determines the injection rate for a treatment, and the optimal pore volume to breakthroughbreakthrough of pore volume, PVbt-opt, suggests the total volume of acid needed for a treatment. Studies of carbonate matrix acidizing have focused on the role of many parameters, such as acid concentration, acid type, temperature, and core dimensions. However, under the same experimental conditions, different limestone rocks exhibit different optimal conditions. It is important to explore how changes in rock properties, such as permeability and pore structure, can also impact the efficacy of matrix acidizing techniques.
In this work, a series of linear core-flood experiments on relative homogenous Indiana limestone and Desert Rose limestone cores were performed at ambient temperature. Cores of 1.5-in. diameter by 8-in. long were acidized using 15% hydrochloric acid. The average permeabilities of the cores tested were 6, 11, 33 and 239 mD with varied porosity. To help understand the effect of permeability on the wormholing process, thin sections were analyzed to characterize the pore structure. Based on experimental results, a detailed explanation of the pore structure and permeability effects on optimal interstitial velocity is presented.
The core-flood acidizing results show that at low permeabilities, high permeability rocks exhibit higher optimal interstitial velocities. When permeability of the rock reaches a certain value, the effect of permeability on the optimal injection condition diminishes. The implications and applications of this work are far-reaching; better understanding of optimal acidizing conditions based on the studied rock properties has significant potential economic and operational impact.
Stochastic Inverse Modelling of Hydraulic Properties of a Real Fractured and Karstic Aquifer Using the Transition Probability Geostatistical Approach
Authors: Wang Xiaoguang , Gosselin Olivier 
Published: May 2015

Abstract
Geological and hydrological data collected at the Terrieu experimental site north of Montpellier, in a confined carbonate aquifer indicates that the aquifer is highly heterogeneous and both fracture clusters and an important bedding plane serve as the main flow paths. However, difficulties in characterising the geometry and location of the main flow channels and in estimating their flow properties have led to significant uncertainties in modelling the hydrodynamic behaviour of the aquifer.
This challenge of reducing these uncertainties can be addressed by solving an inverse problem using the available geological and hydrological data as constraints. We first constructed a 2D equivalent porous medium model by using a transition probability geostatistical approach to represent the test site domain, on which the inverse modelling was performed. A hybrid stochastic-Newton Markov Chain Monte Carlo (MCMC) sampler was used to determine the transmissivity fields on the experimental site scale through the inversion of the steady-state data recorded at 22 boreholes during 8 interference tests. In addition, we used the data from outcrop, borehole fracture characterisations and interpretations of inter-well connectivities from interference test responses to constrain the spatial variability models of the flow properties. Constraints for hydraulic conductivities, based on analytical interpretations of pumping tests, are also added to the inversion model.
By following the above approach, transmissivity fields that produce similar hydraulic behaviours to the real head measurements were obtained. The inverted transmissivity fields show complex spatial heterogeneities with highly conductive channels embedded in a low transmissivity matrix region. The spatial trend of the main flow channels is in good agreement with that of the main fracture sets mapped on outcrops in the vicinity of the Terrieu site suggesting that the hydraulic anisotropy is consistent with the structural anisotropy. These results reduce the uncertainties in predicting fluid flow in the subsurface and improve the hydrogeological understanding of the groundwater flow system within the fractured carbonate rocks. In addition, they quantify the magnitude of the hydraulic conductivity of the main flow paths.
FPWD Illuminates the Path for Brown Field Development in Bohai Bay
Authors: Liu Xiaogang , Tan Lv , Xia Pengyuan , Liu Zongbin , Zhang Bingliang , Zhu Jianmin , Zhang Lei , Nie Xiangbin 
Published: May 2015

Abstract
In Bohai Bay of China, after several decades of field development, including water injection, these brown fields suffer from subsurface heterogeneous pressure profiles. This can result in complications with drilling optimization and reservoir management. This paper is aimed to demonstrate how FPWD (Formation Pressure While Drilling) can be used to identify and applied to address this predicament.
The approach is run in tandem the advanced FPWD tool with the drilling BHA (Bottom Hole Assembly) to measure the reservoir pressure zone by zone to delineate the reservoir's energy profile. Using LWD (Logging While Drilling) measurements including density, porosity and resistivity, the depth of pretests can be picked along the reservoir sections. On each pretest, the FPWD tool will be set against the borehole, to measure drawdown and buildup to a pre-defined sequence before retracting off the wellbore. The final result is a measurement of the reservoir pressure on a defined depth. Consequently the profile of reservoir energy can be drawn. While this information can be used to dynamically adjust the mud weight, it will also provide the reservoir team a higher level of confidence in designing the production and injection program.
3 wells from 3 blocks Bohai bay effectively utilized FPWD for the purpose of drilling optimization and reservoir management. Within the 300 meters interval of a study well, significant fluctuations in pressure were observed, where the largest reservoir pressure measured was 261 psi above the original pressure, and the lowest was 1740 psi below with irregular changes between them. These direct pretest measurements surprised the drilling and the reservoir team as they had never expected that heterogeneity in the reservoir energy was so significant. Following the original mud weight, they would have most possibly faced a kick and severe mud loss. The reservoir team used these measurements to determine the water flooded zones to optimize the final perforation and completion program. This resulted in final production rates that were much better in comparison to its offset wells. On another well, the FPWD measurements are used to determine the connectivity across the fault. Based on the pressure comparison on the both sides of the fault, it could be confidently concluded that the fault was not sealing.
In brown fields, variation in reservoir pressure can far beyond normal expectations. The predicted reservoir pressures from the simulation cannot reveal this variation. Only direct pressure measurements can expose mature reservoir pressure complexity to provide operators with the means to safely and effectively construct wells to develop brown fields.
Interactions of Fines with Base Fractions of Oil and its Implication in Smart Water Flooding
Authors: Chakravarty Krishna Hara , Fosbøl Philip Loldrup , Thomsen Kaj 
Published: May 2015

Abstract
Migration of fines, and formation of oil emulsion have been independently observed during smart water flooding both have been suggested to play a vital role in enhanced oil recovery (EOR). But, the exact role of fines and the reason of emulsion formation are not well studied for carbonate reservoirs. This study shows that addition of water and crude oil on calcite fines leads to formation of soluble oil emulsions in the water phase. Formation of these emulsions and its implication in EOR has been experimentally analyzed.
To characterize the formation of theses emulsions study has been conducted for various water insoluble salts were used as fines (including, Li2CO3, MgCO3, CaCO3, CaSO4, SrSO4, BaSO4 and reservoir CaCO3 fines). Different types of oil and water was added to these fines. To study conditions of oil emulsion formation, design oil was used consisting of hexane and hexadecane. Heptylamine and hexadecylamine were doped in various compositions to mimic the base number of the oil. Experiments were conducted for pure crude oil and doped oil to understand its implications in EOR. Composition of initial and final floating oil was obtained through gas chromatographic (GC) analysis. The two were thereafter compared to obtain the composition of micelles formed.
The experiments showed how oil emulsions were formed when polar hydrocarbons are present in the oil. Mixtures of alkanes did not produce emulsions. In oil containing hexadecylamine 95% of the initial hexadecylamine was accumulated in the emulsions and only 5% was found in the floating oil. In oil samples containing heptylamine only 45-50% of its initial amount was accumulated in the emulsions. This indicates heavier amines can form more stable emulsions. Oil emulsions were produced with all the fines used, but the composition of these emulsions were dependent on the salt anions. In all carbonates, lighter amines preferred emulsions formation with lighter alkane. No such selectivity was observed in any of the sulfates. Results obtained with crude, doped and designed oil were consistent for both pure salts and outcrops. These results show that fines of carbonate released during fracturing, or sulfates formed during smart water flooding can form mixed wet water soluble oil emulsions which help to mobilize trapped oil, and increase the sweep efficiency.
The results clearly show oils with the same base number can have significantly different amount of emulsion formation with fines, and provides a detailed mechanism of further characterization of the oil. The study highlights the significance of fines during smart water flooding in carbonate reservoirs and shows how its role in EOR can be mistakenly underestimated.
Hydraulic Fracturing Performance Evaluation in Tight Sand Gas Reservoirs with High Perm Streaks and Natural Fractures
Authors: Parvizi Hadi , Rezaei-Gomari Sina , Nabhani Farhad , Turner Andrea , Feng Wei Cher 
Published: May 2015

Abstract
Hydraulic fracturing in tight gas sandstone reservoirs increases the connectivity of the well to more reservoir layers and farther areal regions, thus boosting the production as well as the net-present-value of the project. When comparing different well performances, wells that far outperform other wells are usually connected to high permeability streaks or natural fractures. This paper demonstrates the analysis and performance evaluation of hydraulic fractures that are connected to high permeability streaks or natural fractures.
In order for oil and gas operators to consider the development of tight gas sandstone reservoirs economically feasible, stimulation operations such as a large hydraulic fracture treatment of the wells are required. However, the induced fracture is not the main reason for the success of many of the field development in tight gas sandstone reservoirs. In the Southern North Sea, the more productive multiple hydraulically fractured horizontal wells (MHFHW) are usually connected to high permeability streaks or natural fractures. In this work, a reservoir with high permeability streaks and natural fractures was then modelled. This is then calibrated against several years of production and pressure history.
The analysis of core data, borehole image logs, well tests and geomechanics data demonstrated the existence of high permeability streaks or natural fractures in the reservoir. The data derived from the analytical methods were then captured in the simulation model. The simulation model shows a very good match with the history data and when compared with a 3-week long shut-in, the build-up pressure response and its derivative displayed an excellent match. This study shows that, in addition to the role played by the hydraulically induced fractures, natural fractures and high permeability streaks also serve as dominant factors in success of tight gas sandstone reservoir development.
This study demonstrates a practical integrated approach towards the modelling of high permeability streaks and natural fractures that are connected to hydraulic fractures. This can be used to better understand hydraulic fracturing and tight gas sandstone reservoirs in the Southern North Sea.
A Practical Workflow for Offshore Hydraulic Fracturing Modelling: Focusing on Southern North Sea
Authors: Parvizi Hadi , Rezaei-Gomari Sina , Nabhani Farhad , Dastkhan Zohrab , Feng Wei Cher 
Published: May 2015

Abstract
The high prices of energy encourage investments in oil and gas research and development leading to new or improved technologies to recover more hydrocarbons from resources and re-evaluate the reserves. As a result of such technological developments and experience of job practices, hydraulic fracturing techniques have improved significantly in terms of designing and execution and this, at the same time, has made the process much more complicated. This paper suggests a practical multi-disciplinary workflow for hydraulic fracturing modelling mainly in tight gas sandstone reservoirs.
Hydraulic fracturing stimulations in costly environments such as the Southern North Sea require deeper insight into the chemistry and mechanics of the process, characteristics of the formation, and most importantly, the interactions during and after the stimulation job. Different sources of information and analysis such as seismic, reservoir static modelling, initial geomechanical modelling, initial hydraulic fracturing study, fracture initiation point analysis, 1-dimensional (vertical) stress modelling per frac, mini-frac, mainfrac, flowback analysis, well test analysis, and reservoir dynamic modelling are discussed in this paper. The key data cross checks are recognised and lessons learnt from industry are also incorporated to highlight the possible outcomes of different decisions.
Having more information, particularly from different disciplines, can be more productive only if a comprehensive guideline explains the essential elements of the required studies and illustrates their interrelations. This workflow has been the reference of a validated study for a multi-fracced tight gas sandstone reservoir in the Southern North Sea. The workflow has been deployed to organise and recognise the key elements that control the performance of hydraulically fractured wells in a heterogeneous environment. From the workflow, a thorough examination and analysis of available data were performed and fed into the static and dynamic models. As a result of the integrated workflow, a better understanding of the reservoir was formed and potential upside opportunities became visible.
This paper highlights the importance of integrated multi-disciplinary workflow required to detect, characterise and evaluate information from the field into a product that can be used to better understand hydraulic fracturing and tight gas sandstone reservoirs.