bluuebunny/crossref_metadata_2025 huggingface dataset:
Addressing Microseismic Uncertainty from Geological Aspects to Improve Accuracy of Estimating Stimulated Reservoir Volumes
Authors: Yang Sheng , Chen Zhangxin , Wu Wei , Zhang Yonghua , Zhang Xinwen , Deng Haoyun
Published: May 2015

Unconventional resources development has had a great success in North America. But this success has not yet been duplicated in every tight oil or tight gas reservoir. A big challenge is how to correctly demonstrate and evaluate hydraulic fracturing outcomes, which are usually estimated by a stimulated reservoir volume (SRV). Microseismic data is a fundamental element to estimate a SRV. However, most microseismic signals are generated by shear fracturing, while hydraulic fracturing can induce tensile fracturing as well, which cannot be well reflected by microseismic data. A long distance between fracturing places and geophones can also make signals unclear and undetectable. Thus a sole microseismic interpretation has its own limitations. Integrating geological information and microseismic data can provide us with a valuable guide to increase the accuracy of an estimated SRV.

In this study, detailed geological data and well logs are applied to evaluate rock mechanical properties. As known, under the same hydraulic fracturing treatment conditions, a more brittle rock interval can form more fractures, and a rock interval with more natural fractures can generate more complex fractures. The near-wellbore zones are first evaluated by a rock mechanical index based on how the rock is prone to form hydraulic fractures. A rock mechanical model of a whole shale layer is further determined by a Pixel-Based reservoir modeling method. A rock mechanical index is used as a criterion to address the microseismic data uncertainty. Comparing a rock mechanical model with a SRV, some mismatched areas are located, the microseismic uncertainty is addressed, and the microseismic signal threshold criteria are then adjusted in these areas. As a result, a SRV in the mismatched areas is further modified based on a rock mechanical index value and a different signal dataset.

This approach has been applied in the Biyang shale oil reservoir, China. Compared with the successful Barnett marine shale formation, the target shale layer was deposited in a continental lacustrine environment with complex laminations and high heterogeneous rock mineral compositions. Comparing the SRV generated by original microseismic data with the newly SRV generated by applying this approach, the new one can precisely represent hydraulic outcomes and illustrate complex dual-permeability flow for unconventional reservoir development. The proposed approach is a good and valuable guide to increase the accuracy of estimating SRV.
Equation of State Coupled Predictive Viscosity Model for Bitumen Solvent-Thermal Recovery
Authors: Ma Mingxu , Chen Shengnan , Abedi Jalal
Published: May 2015

Exponential and polynomial viscosity correlations have been widely applied to model crude viscosities with temperature. These simple correlations are difficult to be applied to predict the viscosity of different solvent-diluted bitumen systems over a wide range of solvent composition. The Expanded Fluid viscosity model consisting of density as an input parameter can be coupled with an Equation of State in a compositional and thermal reservoir simulator. However, the accurate prediction of density using an EoS is the prerequisite to apply this viscosity model.

In this work, the expanded fluid theory was coupled with the simplified PC-SAFT EoS (Perturbed-Chain Statistical Associating Fluid Theory) to predict and correlate the rheology behaviour of bitumen/solvent systems. Athabasca and Peace River Bitumen was characterized using a proposed eight-pseudocomponent characterization method for PC-SAFT, which simply required distillation and molar mass data. The obtained density was then input into the viscosity theory to model viscosity. Viscosity predictions were obtained using zero viscosity binary interaction coefficients, whereas pressure-dependent and temperature-dependent viscosity binary interaction coefficients were adjusted to improve the effectiveness of mixing rules.

In the case of Athabasca Bitumen with CH4, C2H6, and CO2, the correlated solubility and density Average Absolute Relative Deviations (AARDs) were within 6.6 % and 2.3 %, respectively. Viscosity AARDs by prediction were within 55.4 %; whereas the AARDs were reduced within 13.5 % using pressure-dependent viscosity binary interaction coefficients. In the case of Peace River Bitumen with C2H6, C3H8, n-C4H10, n-C5H12, the predicted density AARDs were within 0.7 %. Viscosity AARDs obtained by prediction were within 24.9 %, and they were reduced within 8.4 % once using temperature-dependent viscosity binary interaction coefficients.
Approximate Analytical Pressure Studies on Dual Porosity Reservoirs with Stress-sensitive Permeability
Authors: Wang Shuhua , Ma Mingxu , Lin Menglu , Chen Shengnan
Published: May 2015

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

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

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

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

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

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

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

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

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.
Near Wellbore and Reservoir Effects in In-Situ Combustion
Authors: Chavez Mario-Luis Rodriguez , Glatz Guenther , Clemens Torsten , Kovscek Anthony
Published: May 2015

In addition to the physical processes relevant in conventional oil production, additional physical-chemical processes have to be considered for in-situ combustion. These processes include heat conduction, steam drive and the kinetics and thermodynamics of combustion.

To determine the kinetic and thermodynamic parameters, kinetic cell and combustion tube experiments were performed.

In this study, oil from a commercially producing in-situ combustion field was sampled. A newly developed kinetic cell was used which enabled performing experiments at various heating rates. The large range of heating rates is used for describing the reactions in the combustion tube and near-wellbore as well as for the conditions at the front in a larger distance from the wells.

The near-wellbore during in-situ combustion is characterized by fast movement of the combustion front, large heating rates at a given location and spatial separation of low-and high temperature combustion reactions.

Once the front propagates further away from the wells, the speed of the front reduces to less than 0.05 m/d. At this speed of the front, heat conduction ahead of the front warms the reservoir up without oxygen being present. Oxygen arriving at the front results in Low and High Temperature Oxidation occurring almost simultaneously.

The far-field conditions were mimicked by pre-heating a kinetic cell prior to exposing it to air. These experiments showed that for these conditions, the high and low temperature oxidation reactions cannot be distinguished and could be approximated by a single reaction.

This study shows that a simplified reaction scheme might be used to simulate the reservoir effects of combustion whereas for simulating the early phase of an in-situ combustion project, a more exhaustive set of chemical reactions might be required.

The results of the study can be used to investigate the start-up phase of an in-situ combustion project (near-wellbore effect focus) and the effects during advancement of the combustion front in the reservoir.

Using the example of a Central European field operated using in-situ combustion in a line-drive configuration, the near-wellbore and far field operational aspects are shown.
Application of Multiple Well Deconvolution Method in a North Sea Field
Authors: Thornton Emma J. , Mazloom Jalal , CNOOC Nexen , Gringarten Alain C. , Cumming Jonathan A.
Published: May 2015

Single-well deconvolution is now commonly used in well test analysis. Within a reservoir, the pressure drop as a function of time is equal to the convoluted product of the rate and the reservoir response at that time. To obtain the reservoir response, inverse convolution – or deconvolution - must take place. This technique, until recently, could only be applied to single-well reservoirs since the deconvolution algorithms assumed zero interference from surrounding wells.

A multi-well deconvolution algorithm was recently presented by Cumming et al, (2013), in which a single-well deconvolution algorithm was adapted to account for interference whilst deconvolving a group of communicating wells. This paper provides further evaluation of the algorithm by applying it to two regions of a North Sea oilfield – the first area including three interfering wells, and the second area including eight interfering wells.

The deconvolved derivatives for four individual wells were analysed for permeability and boundary effects, and the results were in agreement with pre-existing seismic interpretation and geological knowledge of the area. The reliability of the deconvolved derivatives produced by the multiwell algorithm was confirmed by using the algorithm to perform single-well deconvolution and then comparing the results to the outputs from a well-trusted single-well deconvolution tool.

The algorithm also outputs an interference response for each pair of deconvolved wells. Interpreting the interference responses allows to identify relative strengths of communication between wells and to obtain storativity and permeability-thickness of the reservoir between a pair of wells.

It was determined that the run-times of the algorithm were reasonable, and a study of computer run-times is found at the end of this paper whereby some typical multiwell deconvolutions have been run on two different specifications of computer.
Comparative Performance of History Matching Algorithms Using Diverse Parameterization Methods: Application to a Synthetic and North Sea Cases
Authors: Al-Shamma Basil R. , Gosselin Olivier , King Peter , Christie Mike , Mendez Maria
Published: May 2015

Extending the life of the Johnston field requires an ability to produce reliable forecasts of the effects of reservoir interventions. Reliable forecasts need an effective, robust and accurate history match. The goal of this paper is to evaluate the relative performance of three different global assisted history-matching algorithms. We describe the implementation of an integrated parameterization and optimization method, which was tested on the Brugge synthetic model (SPE benchmark case study), and the results based on the best selected method are applied to the Johnston gas field in the Southern North Sea.

There are two key components to assisted history matching: (i) choice of the parameterization, and (ii) selection and performance of the optimization algorithm. In this paper, three parameterization methods are tested (including use of gradients) on three global history-matching algorithms: Particle Swarm Optimization (PSO), Evolutionary Algorithm (EA) and Differential Evolution (DE). A combination of two different algorithms was also examined.

We assessed the algorithm efficiency based on the lowest achieved objective function and the time taken to converge to the lowest value; the quality of the parameterization was examined based on the lowest objective value, the best history match (the most geologically consistent models amongst the lowest objective function models) and the consistency of geological parameters used for the history match.

The results show that the effectiveness of each optimization algorithm is dependent on the parameterization method. When comparing parameterization methods, the Around the Median method seems to give the best results in terms of lowest misfit, and best history match when using the same history matching algorithm for the Brugge model example. When comparing across algorithms the DE method performs better than the rest. An iterative combination of algorithms is seen to be the best option and assists in a further minimization of the objective function. The effect of parameterization on match quality is also proved to be important. In some cases, an iterative process can be effective, where the history match is further improved by adding additional parameters or zoning existing parameters.

This paper stresses and illustrates the importance of the choice of parameterization methods, while many papers focus only on the performances of the minimization algorithm. It also combines gradient-based parameterization method with global optimization method.
Addressing Operator Concerns: Will Surfactant's Performance be Compromised Under Harsh Conditions?
Authors: He Kai , Xu Liang
Published: May 2015

Surfactant is typically pumped during hydraulic fracturing to enhance production from unconventional reservoirs. The primary function of surfactant is believed to generate a short-lived oil-in-water (OIW) emulsion, thereby aiding oil solubilization and mobilization. Ideally, the OIW emulsion should be maintained throughout the entire liquid flow path. However, a temperature gradient typically exists from topside to the interior of the matrix, and the matrix temperature can be high. This temperature gradient is compounded by the fact that, upon dilution by the reservoir connate water, anionic surfactants typically used during fracturing, become more lipophilic at the oil-water interface because of its selective partitioning into the aqueous phase upon dilution or at high reservoir temperature. Therefore, the optimum surfactant formulation cannot be well maintained when the fracturing fluids invade the matrix and reservoir fluids begin to produce. Some nonionic surfactants, on the other hand, typically partition into the oil phase at high temperature or upon dilution. By taking those phenomena into account, an optimum surfactant-oil-water system was created by mixing both anionic and nonionic surfactants to help eliminate the effect of dilution and high reservoir temperature. The new system has been widely used in hundreds of wells in the Eagle Ford (EF) and Mississippi Lime (ML) shale, with favorable production results.
Insights into Whether Low Salinity Brine Enhances Oil Production in Liquids-rich Shale Formations
Authors: He Kai , Nguyen Christina , Kothamasu Ramya , Xu Liang
Published: May 2015

Low salinity water (LSW) flooding has been an attractive technique for enhancing oil recovery. Several LSW mechanisms have been proposed to account for the additional oil recovery, such as interfacial tension (IFT) reduction, wettability alteration, clay migration and microdispersion. However, none of the adequate mechanisms can consistently explain different cases because of the nature of heterogeneity in crude oil and formation rock. Because of a gradual shift from using fresh water to produced water, there is a need to investigate the effects of low salinity on oil recovery from shales to understand potential implications of this shift. Additionally, few studies have been documented on low salinity brines (LSBs) as the fracturing fluids for stimulation applications in liquids-rich shale plays with or without surfactant.

This paper discusses a study in which low salinity surfactant solutions were injected into the Muskwa shale rock from Canada. Laboratory results suggest that LSBs ([LSBs], ≤4% KCl) extract more hydrocarbon than high salinity brines ([HSBs], ≥8% KCl). Notably, additional oil recovery was observed when surfactant is used in LSB. To explore the mechanisms, interfacial tension, emulsion tendency, and reservoir on a chip (ROC) were performed. Interfacial tension reduction was not observed for LSB with surfactants. However, short-lived emulsions were observed in LSB in the presence of a surfactant. Additionally, LSB with surfactant were injected into a microfluidic based ROC device, where the pore size was comparable to that of shale rocks, and the oil recovery that was visualized on ROC was consistent with that found in core flooding tests, and shows the benefit of injection of low salinity surfactant solutions. Based on such observations, two-step mechanisms are proposed for improved oil recovery (IOR) for low salinity surfactant injection: (1) destabilized oil layers (oil/rock) and enhanced pair interaction (surfactant/oil) extract more oil globules and (2) a short-lived emulsion formed by surfactants enables a higher tendency to mobilize the oil globules.

The results suggest a potential methodology for optimizing source water prior to fracturing operations. This study strongly suggests that low salinity and surfactant additives optimization are imperative to enhanced well productivity from liquids-rich shale plays.
New Al-based and Dual Cross-linkers to Form a Strong Gel for Hydraulic Fracturing Treatments
Authors: Sokhanvarian Khatere , Nasr-El-Din Hisham A. , Harper Thomas L.
Published: May 2015

Hydraulic fracturing has been a common practice in US. The chemistry of hydraulic fracturing fluids is very complicated, which makes the optimization process challenging. In designing fracturing fluids, one of the major unknowns is the fluid chemistry. Therefore, understanding the chemistry and interactions between chemicals to form a strong gel is a must. A strong gel is a factor of different parameters such as polymer loadings, crosslinker concentrations, buffer systems, and temperatures.

Different crosslinkers such as boron and several metals including titanium, zirconium, and aluminum have been used in the oil and gas industry. Aluminum and boron reside in the same group on the periodic table. The latter means that there are some similarities in their chemistry. Aluminum chemistry is critical in the preparation of highly effective aluminum-based crosslinkers. Therefore, the objective is to 1) investigate the performance of two new Al-based and Al-Zr-based crosslinkers to form a stable gel with Carboxymethyl hydroxypropyl guar (CMHPG) at high temperatures and shear rates, and 2) determine the leakoff rates of the cross-linked gels with the optimized formulations.

New aluminum-based and aluminum-zirconium crosslinkers to form a stable gel with guar derivatives are studied. This study investigates various parameters including polymer loading, crosslinker concentrations, pH, and temperatures to form a high quality gel. High viscosity gels increases fracture width, and also can carry higher concentrations of proppant that leads to fluid loss decrease and enhances the propant transport.

The results of this study indicate that Al-based crosslinkers at pH 10.8 and 3.8 are very effective in forming high quality gels that are stable at temperatures up to 250°F after 140 minutes. Varying shear rate is studied and the results showed that the Al-based crosslinkers in this study are stable at shear rate of 170 s−1 if an optimized formulations is chosen. It is found that forming a stable gel is strongly a function of concentrations of Al crosslinkers as shear rate increases. Time and temperatures delay in forming gels can be achieved through the optimization of pH, crosslinker concentrations, and polymer loadings.

Extensive lab research and understanding the chemistry of crosslinkers help to design a successful field treatment.
Maintaining Well Productivity Through Controlling Fines Migration and Scale Formation
Authors: Stanciu C. , Vo L.K. , Nguyen P.D. , Weaver J.D.
Published: May 2015

The intrusion of formation fines and formation sand grains into the proppant pack drastically reduces the conductivity of propped fractures, which can negatively impact well production. This paper describes the development and field treatments using a new form of surface modification agent (SMA) that is a low-tackiness surface modification agent (LTSMA) that can be applied during primary hydraulic fracturing or remedial treatments of propped fractures. Studies were conducted to demonstrate the mechanisms by which this LTSMA controls migration and intrusion of formation sand and fines into the proppant pack, while inhibiting scale formation in the treated pack.

Molecular modeling data on the LTSMA suggests that both the polymer backbones and the hydrophobic chains on the polymers are responsible for its reduced tackiness to the treatment equipment and significant scale inhibition ability. Once coated on the proppant as part of hydraulic fracturing treatment, or injected into the proppant pack and formation matrix surrounding the fractures, this LTSMA forms a thin film on the particulates, covering and anchoring the particulates in place. This LTSMA coating also forms a hydrophobic film on the particulate surfaces, inhibiting chemical reactions that lead to scale formation in the pack matrix and subsequent productivity losses.

Laboratory experiments using packed beds of proppant, formation sand grains, and various fines were performed to simulate proppant pack conditions and formation fines before and after remedial treatments. Experimental results indicate that treatments with this particular LTSMA effectively control the migration of formation fines into proppant packs and successfully prevent the buildup of scale in various sand packs to maintain the fluid flow paths. No pressure buildup was noticed, opposed to the proppant that was not treated with the LTSMA, for which severe scaling had occurred by 24 hours, leading to an exponential increase in pressure drop across the proppant pack. Examination with scanning electron microscopy analysis clearly demonstrated that no scale was formed in the pore spaces between the treated proppant grains compared to a massive buildup of scale on the proppant particles and in their pore spaces when not coated with the LTSMA.

In addition to remedial treatments, LTSMA treatment fluid can be applied while treating formations following an acidizing treatment, during treatment of formations before a high-rate water pack or frac-pack treatment, or as part of a pad fluid to treat the fracture faces before placement of proppant into a fracture and/or a screen annulus.
The Value of Inter-well and Single Well Tracer Technology for De-Risking and Optimizing a CEOR Process - Caracara Field Case
Authors: Cubillos H. , Yuste E. , Bozorgzadeh M. , Montes J. , Mayorga H. , Bonilla S. , Quintanilla G. , Lezana P. , Panadero A. , Romero P.
Published: May 2015

Recent advances in tracer technology deliver accurate data in a cost-efficient manner. Tracer applications typically aim to improve reservoir description by solving connectivity questions, to evaluate and derisk the potential for secondary and tertiary recovery processes, along with inflow profiling and allocation of injected water or gas.

A previous paper (SPE-164930) presented the strategy and planning of a chemical EOR (CEOR) process for sandstone reservoirs of the Caracara Sur Field, Colombia. The project is moving forward and laboratory studies have been successfully completed to define an optimum alkaline surfactant polymer (ASP) formulation. Along with simulation studies, comprehensive inter-well (IWTT) and single well tracer tests (SWTT) have been carried out to provide valuable input to understand aquifer drift, the reservoir flooding process and to analyse residual oil saturations to waterflood (Sorw). This paper presents these two tracer applications: IWTTs were performed in Caracara Sur sandstone reservoir zones to characterize aquifer drift. Tracer response was used as input for analysing the implications of chemical dilution by the aquifer and also as an input for history matching, resulting in a more reliable reservoir model.The results of the first SWTT in Caracara Sur Field (and - to our knowledge - in Colombia), are presented. By measuring Sorw, the potential for CEOR application has been confirmed.

An ASP one-spot test has subsequently been completed and followed-up by a second SWTT to evaluate the efficiency of the chemical formulation. Results are currently under evaluation but appear favourable. Planning for expanded use of CEOR in Caracara Sur continues. Lessons learnt and best practices for implementing tracer technology in similar fields include: Use of tracer backflow tests (TBFT) to derisk SWTTs; also the use of FBA passive tracers.Planning, operating and analysing the results of tracer-tests in-house rather than sub-contracting to third parties increases flexibility, increases internal knowledge and is cost-effective.
Prediction of the Minimum Onset Time for Convection in a Gravitationally Unstable Diffusive Boundary Layer Using a Finite Difference Pressure Solver
Authors: Taheri Amir , Wessel-Berg Dag , Torsæter Ole
Published: May 2015

CO2 dissolution as one of the most promising mechanisms for trapping of CO2 free phase into brine causes increased density of the brine and initiation of gravitational instability that eventually leads to density-driven natural convection in brine aquifers. The gravitational instability of a diffusive boundary layer in porous media has been studied in several papers in recent years and there are several methods in the literature for prediction of the onset time for convection and the related unstable wavelength.

In this study we present a numerical solution for prediction of the critical time for the onset of convection and the critical unstable wavelength in semi-infinite anisotropic homogeneous brine aquifer models. A finite difference pressure solver is used for solving this numerical problem. The numerical model is initialized by the recent developed approach and the gravitational instability is triggered by a weak wavy perturbation with dimensionless wavenumber of K. The minimum of the calculated time for onset of instability as a function of wavenumber is called the critical time and the associated wavenumber to this critical time is the critical unstable wavenumber. The results of this analysis shows acceptable agreement with previously published ones derived from other methods. By applying this prediction approach in more complex numerical models, their related critical time for the onset of convection and the critical unstable wavelength can be calculated.