bluuebunny/crossref_metadata_2025 huggingface dataset:
Numerical Simulation of Natural Gas Flow in Shale Reservoirs with Thermodynamic Equation of State: A Comparative Study
Authors: Negara Ardiansyah , Elgassier Mokhtar , Saad Bilal
Published: April 2016

Production from unconventional reservoirs like shale gas has increased considerably in the past few years due to the advancement in twofold, i.e., horizontal drilling and hydraulic fracturing technologies. Although there has been some success in increasing gas production from shale reservoirs, unfortunately, the physicochemical processes that take place in the shale formations remain challenging and are not completely understood. Unlike conventional reservoirs, shale reservoirs are characterized by very small porosity and extremely low-permeability. Gas flow in this tight formation involves complex flow processes such as Knudsen diffusion, Klinkenberg effect, adsorption and desorption, strong rock-fluid interaction, rock deformation, etc. Furthermore, because of high pressure and high temperature reservoir conditions the gas behaves as real gas. In this work, our shale gas mathematical model is built based on the dual-porosity dual-permeability model that incorporates the complex flow processes mentioned above as well as the thermodynamic calculations. Peng-Robinson equation of state (PR-EOS) was used to calculate the gas density and compressibility factor by solving the cubic equation. In the numerical method implementation we combine the finite difference method with the experimenting pressure field approach to solve the pressure equations for the matrix and fracture systems in the dual-porosity dual-permeability model. This combination greatly reduces the computational cost when solving the large systems of pressure equations of the matrix and fracture. In this approach, a set of predefined pressure fields is generated in the solution domain such that the undetermined coefficients are calculated from these pressure fields. In the numerical example, we considered a shale reservoir with single production well. Comparison between real gas and ideal gas is studied and the result shows that considering the real gas behavior generates higher cumulative production, which implies that the gas transport capacity is higher than the ideal gas case. The result also indicates that considering real gas behavior in the model would increase the production and retard the decline curve. Therefore, it is very important to incorporate the real gas behavior into the model in order to be able to forecast the production accurately.
Simulation of Complex Composite EOR Processes at Lab and Field Scale
Authors: Pettersen Øystein , Skauge Arne
Published: April 2016

Experiments on injection of composite EOR fluids, simultaneously or sequentially, have been validated by small scale simulation, with cell sizes in the millimeter-range. The injected fluids have been a combination of low-salinity brine, surfactant, and polymer. This presentation addresses the challenges of extending the lab scale results to larger models, up to field size.

The complex injection scheme itself is not straightforward to model in any simulator, and novel techniques have been developed to handle this. The main mechanisms that must be addressed are concentration dependent properties for all fluids involved and any combination of these, e.g. relative permeability and viscosity. The methods used have been adapted to both a black oil simulator, and a composition based simulator. As the basic modeling principles for black oil and compositional simulators are per se very different, the way of handling fluid descriptions from the user view point are naturally quite different for the two approaches. Hence also adaption to the composite processes necessarily differs.

History matching (validating) experiments at lab scale was successfully done with both simulators, with qualitative equal though not identical results. When attempting to generalize results to larger models, two issues have been addressed; extension, where the size of the simulation model was increased without changing the grid resolution (cell size), and upscaling, where model size was unchanged while grid cell sizes were increased. Ideally, simulated results should be identical at different scales and grid resolutions, at least within standard grid resolution errors. Both simulators were well-behaved with respect to upscaling, while the compositional simulator handled extension better than the black oil simulator. Moreover, the black oil simulator was found to be very sensitive to smoothness of relative permeability curves. As example, using a relative permeability curve that was determined by history matching of a lab experiment was not successful.

One magnitude that had to be focused on was simulated pressure. Simulated injection pressure and resulting average pressure during polymer injection was not in agreement with field observations, probably because the simulators do not include all the complex mechanisms of polymer flood. Hence maintaining reservoir pressure within a reasonable range during simulation turned out to be a challenge, especially for the black oil simulations.

In conclusion it was found that with the appropriate approach, robust and reliable results could be obtained at scales less than some critical value, consistent with similar results obtained for pure water flood simulations. Compositional simulations were apparently more reliably scaled than black oil simulations. An important finding was that results were extremely sensitive to correct and consistent definition of fluid descriptions, and users must be aware of different approach angles for compositional and black oil simulators in this respect.
Comparing Different Scenarios for Thermal Enhanced Oil Recovery in Fractured Reservoirs Using Hybrid (Solar-Gas) Steam Generators, A Simulation Study
Authors: Yegane Mohsen Mirzaie , Bashtani Farzad , Tahmasebi Ali , Ayatollahi Shahab , Al-wahaibi Yahya Mansoor
Published: April 2016

The application of the renewable energy sources, especially solar energy, for thermal enhanced oil recovery methods as an economical and environmental valuable technique has received many attractions recently. Concentrated Solar Power systems are capable of producing substantial quantities of steam by means of focused sunlight as the heat source for steam generation. This paper aims to investigate viability of using this innovative technology in fractured reservoirs to generate steam instead of using conventional steam generators.

A synthetic fractured reservoir with properties similar to those of giant carbonate oil reserves in the Middle East was designed by using commercial thermal simulator. The dual porosity model was used to account for differences in matrix and fracture parameters. Different cyclic and continuous steam injection scenarios using combination of both solar energy and fossil-fuel to generate steam were designed. The cyclic scenarios were different in terms of contribution of solar energy in steam generation and in case of 100% solar scenario a small nightly steam injection using fossil-fuel was suggested to prevent flow back into the wellbore.

It was assumed that total amount of injected steam in 10 year time period is the same for all the scenarios regardless of how steam was generated. Simulation results showed that nightly injection of insignificant amount of fossil-fuel-generated-steam in a 100% solar-generated-steam injection process increases the cumulative oil production compared to 100% solar-generated-steam injection system with no nightly injection. Furthermore, there was no significant difference between the final oil recoveries for all the designed cyclic injection scenarios. Although continuous steam injection scenario had the highest final oil recovery among all scenarios, a detailed economical study showed that net present value for 100% solar-generated-steam scenario is the highest. An environmental analysis on all scenarios also indicated significant reduction of CO2 emission into the atmosphere for the latter scenario.

Therefore, hybrid steam generators which utilize solar energy instead of traditional fossil-fuel for steam generation is proposed for Middle East fractured reservoirs where there is abundance of sunshine during day time. The findings illustrate high economic efficiency of solar-generated steam injection and highlight it as a green EOR method.
Theoretical Analysis and Experimental Research of Channel Fracturing in Unconventional Reservoir
Authors: Hou Tengfei , Zhang Shicheng , Yu Baihui , Lv Xinrun , Zhang Jingchen , Han Jingyu , Li Dong
Published: April 2016

Channel fracturing, which greatly increase fracture conductivity by the creation of open channels inside fracture, has proved to be a novel stimulation technology that widely used in unconventional reservoir. The objective of this paper is to study the stimulation mechanism of channel fracturing by the combination of theoretical analysis and experimental research. However, for channel fracturing scenario, the currently available models are not accurate and appropriate in terms of prediction of proppant embedment and fracture conductivity in channel fracturing.

In this paper, new analytical models are derived to compute the proppant embedment, proppant deformation and fracture conductivity in channel fracturing. The mass deformation model and creeping deformation model are adopted to predict the change of proppant embedment and fracture conductivity over time. Many factors affecting the results of proppant embedment and conductivity, including closure pressure, elastic-plastic properties, properties of viscoelastic proppant and rock are investigated. Experimental researches are also conducted to evaluate conductivity at different closure pressures for the fractures of steel plate, shale and sandstone. Besides, the proppant embedment and proppant deformation are measured through the proppant embedment testing instrument, and the proppant distribution before and after experiments are comparatively analyzed.

The results show that the new analytical model proposed fits well with the experimental data, which verifies the accuracy and the feasibility of this model, though the decline rate of experimental data is a little bit faster than that of the model. The fracture conductivity is directly proportional to proppant viscosity, elastic modulus of proppant and inversely proportional to closure pressure, while elastic modulus of rock and large value of formation rock viscosity have slight impact on fracture conductivity. Moreover, the steady state of conductivity has been studied, and Comparisons between channel fracturing and conventional fracturing are analyzed in several aspects. The experimental results also reveal that the overall dimensions of created open channel may decrease or disappear due to the forced of formation stress.

Technical innovations in this paper are (a) new analytical models, including the mass deformation model and creeping deformation model, are adopted to predict the change of proppant embedment and fracture conductivity (b) Experimental tests are also performed to measure conductivity and proppant embedment at different closure pressures. This paper can demonstrate its own merits to show the advantage of channel fracturing technology.
Verification Of Geological Models With One Single Simulation Run
Authors: Mittermeir Georg M. , Steiner Christoph , Gharsalla Mohamed M. , Heinemann Zoltán E.
Published: April 2016

This work suggests a paradigm change. Instead of history matching an (upscaled) geological model by the reservoir engineer focusing on matching the dynamic data. The model builder should be equipped with the right tools to identify areas where the geological model cannot fulfill the dynamic requirements. The target is to make history matching obsolete. Every modification of the model must have its geological reasoning and justification. Introducing artifacts for the sole target of matching dynamic data is depreciated. Often such models lack forecasting credibility. Especially selecting infill drilling locations becomes highly uncertain. This paper presents applicable and ready to use methods which will be demonstrated on a full-field project.

There are two key elements, each to be fulfilled during every timestep. At first the average (region) pressures must fit and second each well must be allowed to search for the required phases to satisfy its production targets. The first requires at least one region for which the historic pressure decline is known. At the delineation towards an outer aquifer water will be automatically injected/withdrawn to match the pressure history. The second is realized by perforations (well-grid-connections) which are allowed to move away from the well's trajectory and to search for the required phases within a user or algorithm defined drainage area. There is just one restriction. Drainage areas must not overlap. In case the drainage area does not contain the necessary fluids the geological model has to be revised. At the same time important information about fluid movements are gathered.

The promoted concept was successfully applied to a North African naturally fractured carbonate reservoir having more than 500 MMstb original oil in place and a 35-years production history. The reservoir was divided into eight pressure regions. Five were selected as target for the automatic pressure match, the remaining three were control regions. Two update cycles were performed. During the first cycle the structure was corrected. Thus the phase distribution was affected so that all drainage areas could produce the required historic rates. During the second cycle local adjustments in porevolume and communication across faults were performed to increase the pressure match of the control regions. The demonstrated workflow has the potential to revolutionize the commonly practiced reservoir model creation.

Up to now no similar workflow allowing to assess the geological model quality within one single simulation run was published. It is unique that pressure and production targets can be met in each timestep without corrupting the underlying geological model. Contrary the modeler is provided with the required information where and how to improve the geological model.
Experimental and Numerical Studies of First Contact Miscible Injection in a Quarter Five Spot Pattern
Authors: Djabbarov Sultan , Jones Alistair D , Krevor Samuel , Muggeridge Ann H.
Published: April 2016

We quantify the impact of mobility, simple heterogeneities and grid orientation error on the performance of first contact miscible gas flooding in a quarter five spot configuration by comparing the outputs from experimental and numerical models. The aim is to quantify the errors that may arise during simulation and to identify a workflow for minimizing these when conducting field scale fingering studies.

A commercial reservoir simulator was validated by comparing its predictions with the results obtained from physical experiments. An uncorrelated, random permeability distribution was used to trigger fingering in the simulations. The physical experiments were carried out using a Hele-Shaw cell (40×40cm) designed and constructed for this study. The impact of a square low permeability inclusion (20×20cm) on flow was investigated by varying its permeability, location and orientation.

For lower mobility ratios (M=2 to M=10) the commercial numerical simulator was able to reproduce the experimental observations within the uncertainty range of the permeability distribution used to trigger the fingers, provided a nine-point scheme was used for the pressure solution. At higher mobility ratios (M=20 to M=100) the grid orientation effect meant that the simulator overestimated the areal sweep even when a nine-point scheme was used. The introduction of a square, low permeability inclusion near the injection well reduced the discrepancy between experimental and numerical results, bringing it back within uncertainty limits in some of the cases. This was mainly because the real flow was then forced to move parallel to the edges of the Hele-Shaw cell and thus parallel to the simulation grid. Breakthrough times were well predicted by the numerical simulator at all mobility ratios.
Gas Flow Transport in Shale Matrix: Simultaneous Effects of Stress and Slippage on Matrix Permeability
Authors: Moghaddam R. Nazari , Jamiolahmady M.
Published: April 2016

Gas flow modelling in shale and tight gas reservoirs is still challenging mainly due to different pore-scale flow regimes present in micro- and nano-pores of these reservoirs. The effect of geomechanical stress also significantly affect the measurement and prediction of apparent matrix permeability. In this study, series of experiments were designed and performed on three shale samples to study the simultaneous effects of slippage and stress at five different pore pressures and four net stresses. The experimental data were used to obtain a general slip plot, which quantifies the effect of slippage on matrix permeability. Then, the stress effect was taken into account by modifying the average pore size and non-slip permeability at each net stress based on the experimental observations. It is found that the matrix non-slip permeability and average pore size follow an exponential behaviour when changing the net stress. These two relationships are then proposed to be incorporated into the corresponding slip flow model in order to capture the effects of slippage and stress at the same time. The validity of the proposed model was also investigated (using published data in the literature), which shows that the proposed technique is able to capture the intensity of permeability reduction and enhancement due to stress and slippage, respectively. The outcomes of this study increase our knowledge of rarefied flow dynamic inside micro- and nano-pores under confining stress, which is necessary for accurate predictions of the apparent matrix permeability in unconventional reservoirs.
Water-Soluble Sodium Silicate Gelants for Water Management in Naturally Fractured Carbonate Reservoirs
Authors: Hatzignatiou Dimitrios G. , Giske Nils H.
Published: April 2016

Fluid diversion gels, normally formed from polymer/crosslinker gelants, are often used to control injected water in oil-bearing formations. Injected fluid diversion becomes more important, and well treatment design requirements more challenging, in naturally fractured carbonate (NFC) formations due to the presence of highly conductive fluid pathways. The goal of this work is to screen and evaluate two commercially available, and environmentally friendly, sodium silicate gelant systems that may be used for water management in NFC reservoirs.

HSE regulations may not permit the use of field-tested and successfully applied polymer-based gelants for water management. Strict environmental constraints on Norwegian Continental Shelf (NCS) require the use of "green" chemicals for any type of chemical field intervention. Several bulk- and core-based testing techniques have been engaged in this work, with the two investigated water-soluble silicate gelant chemicals having undergone through careful investigation of their filterability, injectivity, gelation time, gel strength, and gel shrinkage. The gelant impact on oil production was examined and the ability to reverse poorly deployed gel treatments in the field through gel dissolution was also investigated.

Two commercial, water-soluble, green sodium silicates (Silicate A and Silicate B) have been examined. Activators used were NaCl solution, although other chemicals (e.g., Ca2+, Mg2+, HCl and HCOOH acids) have a similar effect, hydrochloric acid (HCl), nitric acid (HNO3), formic acid (HCOOH), and urea depending on the silicate used. Silicate A is a commercial product and Silicate B is a silicate system that has been used in North Sea for matrix treatment. Gelation, in either gelant, is mainly controlled by the activator type and concentration, silicate concentration and temperature. Normally, formed gel strength could be improved by increasing the injected silicate concentration but in Silicate B experiments, gelation difficulties were experienced for concentrations of approximately above 7 wt%.

Filterability of Silicate B is significantly better than that of Silicate A. Fractured core tests using Silicate A gelant revealed that the average core permeability was reduced by three orders of magnitude between prior- and post-gelation conditions. Silicate B gelants exhibited "difficulties" in the gelation process and formed gels displayed a lower strength compared to ones for Silicate A gels. Unsuccessfully deployed gels may be reversed through dissolution with alkaline fluids such as NaOH or KOH; the gel dissolution rate is a function of the alkaline fluid concentration and the type of process used. Overall, Silicate A outperforms Silicate B in several tests and shows promising properties for its potential utilization in field applications to control injected water in NFC formations.
Economic Development of Long Transition Zone Aeolian Sandstones with Hydraulic Fracturing
Authors: Jutila Heikki , Kshirsagar Atul , Samy Ayman , Rivero Luis , Monaghan Niamh
Published: April 2016

A large amount of gas is trapped in the transition zones in tight, conventional reservoirs. These reservoirs tend to be prone to water production because the in-situ water saturation is at or exceeds the critical water saturation. The water-production issue is even more pronounced when wells are stimulated by hydraulic fracturing; the resultant water production might be interpreted to have its source in the aquifer below the free water level to a bad cement job or a connection to unknown faulting.

As an example, a typical Rotliegendes Sandstone well was considered. It was completed and subsequently fractured, and produces gas with a high water-gas ratio. The objective of this study was to demonstrate how to ascertain the most likely source of the water; whether it was produced from the aquifer or from high water saturation matrix regions in the reservoir.

Available fracture placement data were used to match analytically the pressures to confirm the stresses with the resultant fracture model compared with the one used for initial design. A box model was constructed in a reservoir simulator and the fracture was described using a Tartan grid. Using the analytical result as a base case the reservoir and fracture properties were adjusted using assisted history matching to replicate observed gas and water rates and flowing bottomhole pressure. The main matching variables were permeability, permeability anisotropy, stand-off to gas-water contact, relative permeability, gas and water end points saturations and fracture dimensions. The water saturation was derived from a saturation vs. height function; the power law factors in this equation can also be matched.

Analysis of the fracture delivery indicated that the dimensions of the fracture could be different from the dimensions derived from the design. The fracture height and half-length in the post-fracture model showed a higher fracture height and a smaller half-length connecting potentially with free water. The assisted history matching demonstrated that the water rate behavior could best be explained as a result of high water saturation in the reservoir, rather than direct connection to the aquifer through an inadequate cement bond or fault. A range of predictions was provided to describe the range in estimated ultimate recovery of a single typical well. The completion design will cater for active dewatering of the well.

Because great uncertainty exists about the propensity to water production, the optimal well design will be flexible enough to allow for de-watering throughout the life of the well.
Common Misconceptions in Subsurface and Surface Risk Analysis
Authors: Ward Gavin , Whitaker Simon
Published: April 2016

This paper is intended to highlight some of the misconceptions that enter decision making whether as a consequence of human bias or as statistical inaccuracies and misuse of mathematically robust equations.

There are three basic questions in the oil and gas industry: 1) How big is it? i.e.: Resources, 2) How quickly can we get it out? i.e.: Rate, and 3) How much can we make from it? i.e.: Value. All three contain risk and uncertainty. Several methods are used by oil and gas professionals to manage these variables, ranging from the simple toss of a coin, to complex mathematical algorithms and statistics. If only it were so simple to use a formula for the decision and have the confidence to trust it. However, business decisions are often more than just complex logic and the worlds of subsurface geoscience and reservoir engineering add yet more variables and uncertainty.

The paper uses real world examples in the oil and gas industry and highlights the difference between Risk Management and simple Gambling. The paper draws upon the following three themes: Human Factors: No matter how precise the mathematics of risk analysis, ultimately decision making relies upon individuals who are subjective by definition. A group of similar but independent professionals will have a different perception of risk and their own biases depending upon the number of parameters used to calculate for example, chance of success and different biases on marking at extremes of a range.Statistics: One solution to deal with the human variable is to attempt to take individuals out of the decision making process completely and trust mathematics instead. Unfortunately, many decision makers have forgotten what assumptions exist in Portfolio Theory and often use the methods blindly, placing too much confidence in the predictions and unaware of other equally likely outcomes.Popular Decision tools:Expected Monetary Value – ‘Expected’ is a subjective term and numerically tends towards the Mode of the distribution. The authors question whether EMV really has any true meaning and instils a false sense of confidence in the outcome.Hurdle Rates - The Theory of Inevitable Disappointment highlights how a decision maker who fails to understand uncertainty can often fall short on forecasts.

Conclusion: There are no simple rules when decisions involve information which contains uncertainty and interpretation. The responsibility for decision making should rest with individuals with ‘skin in the game’. A decision maker should be aware of all assumptions and always question those assumptions. In the end, if a decision maker does not use a spectrum of tools to examine all possible outcomes, then they are simply relying on luck. Whatever the process, review, feedback and calibration are critically important.
Application of Polymer-Gel Solutions in Remediating Leakage in CO2 Storage Reservoirs
Authors: Hadi Mosleh Mojgan , Govindan Rajesh , Shi Ji-Quan , Durucan Sevket , Korre Anna
Published: April 2016

The application of crosslinked gels has seen widespread use within the petroleum industry to divert fluid flow and remediate leakage at wells. The current study aimed at investigating the effectiveness of polymer-gel treatment in remediating a potential CO2 leakage site in the subsurface. This paper presents a brief summary of the results of laboratory characterisation work carried out on polymer gels, which involved characterisation of several polymer-gel systems with respect to their working and gelation times and conducting core flooding experiments on reservoir rocks to characterise their permeability reduction behaviour. The chemical flooding reservoir simulator, UTCHEM, was used to simulate polymer injection and its subsequent gelation process in the saline aquifer model. Parameters such as polymer concentration, polymer to crosslinker ratio and pH, and their influence on the gelation process and the area of influence have been investigated.

The results have shown that lower polymer to crosslinker ratios lead to a relatively higher gel concentration. On the other hand, higher polymer to crosslinker ratios result in a relatively higher area of influence, which is mainly due to the decreased viscosity and slower gelation rate. It was also found that, as the concentration of H+ in the injection stream increases, the rate of crosslinking decreases and the lower viscosity polymer slug migrates to the far-field region of the reservoir formation.
Gas Storage in Model Kerogen Pores with Surface Heterogeneities
Authors: Cristancho Dahiyana , Akkutlu I. Yucel , Criscenti Louise J. , Wang Yifeng
Published: April 2016

Experimental techniques have limited applicability in investigating the nature of fluid storage in kerogen pores under subsurface conditions. In this paper we present a computational chemistry approach and present new numerical results on supercritical methane storage influenced by nano-scale pore confinement and pore wall surface heterogeneities. The results show that gas amount stored in the pore is not strongly correlated with nano-pore confinement. Measured excess amount due to confinement is most pronounced at pore pressure in the range of 1,000-5,000 psi. The pore wall surface heterogeneities have the potential to impact storage depending on the type and level of heterogeneities. Among the investigated heterogeneities, nitrogen-doping at the pore walls is found to be the most influential. The adsorbed amount decreased up to 63% and the excess amount increased up to 37%, with the nitrogen-doped pore wall surfaces. The net storage is inversely correlated with the concentration of the nitrogen atoms. The results indicate that kerogen maturation and the associated changes in its composition has the potential to impact gas storage and transport in resource shale reservoirs. The work gives insight into the potential impact of the surface effects on natural gas storage in kerogen and emphasizes the significance of knowledge on the source rock geochemistry.
Optimizing Water Injection in a Shallow Off-Shore Reservoir
Authors: Kienberger Gerhard , Clemens Torsten , Persaud Mira , Suri Ajay , Sharma Mukul M. , Boschi Marcelo , Overland Alf M.
Published: April 2016

Water injection is commonly used to improve oil recoveries in depleting reservoirs. However, insufficient injectivity can result in water injection projects being limited in injection rates which can sometimes make them uneconomic. Implementing water injection projects requires a multi-disciplinary approach to optimize water injection rates for reservoir performance, costs and well design considerations.

The costs for the surface facilities are dependent on the required water quality, water temperature and other operating parameters which are linked to the injectivity of water. A workflow including quantitative assessment of the injectivity development as a function of the operating parameters as well as the uncertain geomechanical and reservoir parameters can be used to improve the surface facility design.

Such a workflow was applied to a shallow off-shore field. The results showed that the base case design of the facilities should be modified to avoid an increase of the flowing Bottom Hole Pressure (BHP) above the minimum stress of the caprock. The effect of the various parameters on the BHP was investigated and the sensitivity of the BHP to uncertain input parameters under different operating conditions was tested. The results indicated that the BHP does not exceed the BHP limit and hence, the injectivity is expected to be high enough for a sufficiently long period of time under a wide range of conditions.
Integration of Pressure Transient Data Into Reservoir Models Using the Fast Marching Method
Authors: Li Chen , King Michael J.
Published: April 2016

In this study, we utilize the concept of the ‘diffusive time of flight’ (DTOF) to formulate an asymptotic solution of the diffusivity equation that describes transient flow behavior in petroleum reservoirs. The DTOF is obtained from the solution of the Eikonal equation via the Fast Marching Method. It may be used as a spatial coordinate which reduces the three dimensional diffusivity equation to an equivalent one dimensional formulation. We investigate the ‘pressure front’ propagation and the drainage volume evolution as a function of time in terms of the DTOF. The drainage volume may be directly related to the well test derivative which may be used in an inversion calculation to calibrate reservoir model parameters.

The analytic sensitivity coefficients of well test derivative with respect to reservoir properties are derived and incorporated into the objective function to perform inverse modeling. The key to formulating the sensitivity coefficients is to utilize the functional derivative of the Eikonal equation to derive the analytic sensitivity of the DTOF to reservoir permeability and porosity. Its solution is implemented by differentiating the local solver within the Fast Marching Method (FMM). The major advantage of formulating sensitivity coefficients using the FMM is its great computational efficiency while inversion is conducted.

Unlike the traditional means of estimating bulk reservoir permeability by interpreting the diagnostic plot of the well pressure and production data, the methodology adopted in this inverse modeling study can help generate more accurate spatial distributions of permeability through integration with a prior geologic model. Sensitivity studies are performed on synthetic permeability and porosity fields to analyze magnitudes of response in space and time to the well production. By taking sufficient a priori information into account, the permeability distribution after inversion matches well with reference reservoir model properties. Integration of the well test data into the subsurface using the FMM demonstrates that our proposed inverse modeling approach can predict pressure depletion behavior in the petroleum reservoir, while remaining consistent with a prior geologic static model.
Asymptotic Solutions of the Diffusivity Equation and Their Applications
Authors: King Michael J. , Wang Zhenzhen , Datta-Gupta Akhil
Published: April 2016

Understanding how pressure fronts propagate (diffuse) in a reservoir formation is fundamental to welltest analysis and reservoir drainage volume estimation. We have developed an alternative approach to the solution of the 3-D diffusivity equation by directly solving the propagation equation for the "pressure front" defined as the maximum pressure response for an impulse source. The pressure front equation is a form of the Eikonal equation, which is a high frequency asymptotic solution of the diffusivity equation in heterogeneous reservoirs and whose properties are well developed in the literature. Most importantly, the Eikonal equation can be solved very efficiently by a class of solutions called the Fast Marching Methods (FMM) for a "diffusive time of flight" (DTOF) that governs the propagation of the "pressure front" in the reservoir. The "diffusive time of flight" can be used as a spatial coordinate to reduce the 3-D diffusivity equation into an equivalent 1-D formulation, leading to a simplified method for rapid reservoir modeling. Recent papers have explored the utility of this 1-D approach for performance prediction using finite difference numerical simulation. The method is especially well suited to the interpretation of the drainage volume, which is of great help in well spacing calculations and in the context of unconventional reservoirs, multi-stage fracture spacing optimization.

In this paper we introduce an analytic solution technique for the diffusivity equation, which provides a direct relationship between production data and the reservoir drainage volume. The analytic formulation provides for the direct calculation and extension of many simple well test, rate transient and well performance concepts such as depth of investigation, welltest derivative, drainage volume, flow regimes and well productivity. As with other analytic approaches, these solutions allow superposition in space and in time, which allows for the solution for multiple wells, multiple flow rates, and bounded and composite reservoirs. We validate our approach against well-known solutions in pressure and rate transient analysis usually solved in Laplace space, including pressure transients with wellbore storage and skin. Our study demonstrates that the new approach yields results very close to the known solutions calculated via numerical inversion of the Laplace transform, and indicates how to extend these solutions to problems with heterogeneity and complex fractured well geometry.
Successful Execution and Analysis of a Multistage Frac Treatment in a Horizontal Gas Well in the Grove Field, UK Southern North Sea
Authors: Gijtenbeek Klaas van , Taku Khan , Langford Marc , Green Christopher A.
Published: April 2016

The Grove field is located in the Southern North Sea and has been in production since 2007. The Grove A well lies within block 49/10a and was originally planned by Centrica as an infill well, drilled horizontally in the central fault compartment of the Grove field structure. The well targeted the relatively undepleted basal "A" sandstone unit of the Late Carboniferous, Westphalian reservoir, also known as the Barren Red Measures (BRM).

The well objectives were to 1) target the Grove A sand from the G1 "donor" well, 2) establish a suitable completion strategy for field development, 3) assess the performance of a multiple stage (four to five) hydraulically fractured horizontal well, 4) acquire sufficient log data to fully evaluate the reservoir, and 5) acquire reliable permeability and reservoir pressure measurements to assist in reservoir simulation.

The A sand reservoir unit has a porosity of approximately 10% and permeability between 0.05 to 1 md, with a reservoir with true vertical thickness (TVT) of approximately 140 ft at the heel and 40 ft at the toe. The reservoir unit is poorly drained by the other wells, and the Grove infill well is the first horizontal gas well in the field to be stimulated by means of multistage hydraulic proppant fracturing. The hydraulic fracturing treatment used sand plug isolation to separate consecutive fracture stages, and the fracture stimulation operations were performed with the rig in place by means of a converted stimulation vessel. The stimulation treatments successfully used a modified sand plug methodology that employed aggressive breaker schedules and fluid injections rates that were determined to be more efficient than previous treatments based on employing strict "sand plug setting" criteria. The findings are presented, as well as analyses of both prefracturing and fracturing data for the treatments together with results of the well post-completion and hook-up production.

This work should be of interest to offshore operators world-wide performing multiple hydraulic fractures in both horizontal and vertical wells using sand plug isolation technology.
Production Acceleration in a Key Reservoir by Proactive Well Placement, Utilizing Innovative Logging-While-Drilling LWD Technology in the Vienna Basin, Austria
Authors: Toth P. , Knezevic R. , Blanzano A. , Chinellato F. , Vergani V. , Gorshenina O. , Dolan J. T.
Published: April 2016

The transgressive sandstones of the Badenian 16.TH reservoir have been on production for over 65 years. As part of a recent field re-development project the oil production has been accelerated with high-angle/horizontal wells. Targeting drainage areas to access attic oil with the accurate placement of these boreholes was deemed business critical. Previous mapping efforts did not capture the undulating structural nature of the top of the first sand layer. Since the "sweet spot" of the reservoir was assumed to have a gross thickness of 1 to 2 meters, the application of proactive geosteering with the latest Logging-While-Drilling (LWD) technology was viewed as essential. This paper describes the placement of two wells, which benefited from active geosteering based on the data transmitted and interpreted in real-time.

A multilayer bed boundary detection service was the primary source of information to place the boreholes close to the target formation top and to map the presence of fluid transition zones. Deep azimuthal electromagnetic measurements enabled continuous real-time, 360 degree, mapping of the direction and distance to resistivity changes in the formation. Conventional LWD logs (gamma ray, nuclear, and resistivity measurements) provided formation evaluation and saturation estimation while drilling. The rotary steerable system completed the drill string and ensured directional control.

Proactive decision-making used real-time inversions to optimize the landing and improve well placement, since critical data - distance to boundary, geometry of the remote reservoir top and fluid changes in transition zones - were available in real time. In all wells the trajectory was maintained within the zone of interest by taking the proactive, real-time decisions while drilling. The integration of multilayer inversion results with recorded borehole images enabled a comprehensive interpretation and detailed 3D structural modeling in the post-job phase. Sub-seismic faulting and local dip changes were revealed that were not predicted in the pre-drill geological model. Finally, structural information, formation evaluation results, and oil-water transition zone mapping were used to optimize completion design to delay the increase in water production.

The production results confirmed the anticipated volumes, proving the advantages of the innovative LWD applications and their capability for optimized placement of such production wells. The use of the directional multilayer detection service aided structural interpretation, definition of the reservoir geometry and the position of the current fluid transition zones. This in turn led to improved accuracy in the description and understanding of the reservoir.
Multiwell Deconvolution for Shale Gas
Authors: Tung Yit , Virues Claudio , Cumming Jonathan , Gringarten Alain
Published: April 2016

In the last decade, single well deconvolution (von Schroeter et al., 2001) has become recognised as a powerful tool for reservoir characterization. Deconvolution transforms well test pressure data measured at varying rates into an equivalent unit rate single drawdown which has the same duration as the pressure history and can be analysed using conventional techniques to identify boundaries and assess connectivity between different compartments and layers. As its name suggests, single well convolution is only applicable when there is no interference from other wells. i.e. to exploration, appraisal and isolated production wells.

In 2013, a multiwell deconvolution algorithm was presented (Cumming et al., 2013) which enables deconvolution to be applied to groups of interfering wells. The algorithm yields a unit rate deconvolved derivative for every well, representing the well signature with interferences removed; and the interference derivatives between well pairs. An example of use with eight interfering North Sea oil wells was presented by Thornton et al. (2015).

This paper describes the application of the Cumming et al. multiwell deconvolution algorithm to eight wells in a multilayer shale gas reservoir. The main objective of the study was to verify the capability of the multiwell deconvolution algorithm to remove the effects of interference between horizontal wells and to assess the efficiency of the actual well spacing, which had been intended to avoid interferences. This study can have an impact on upcoming LNG projects in Canada and other countries which are evaluating LNG prospects.

An additional objective was to identify an optimal testing procedure to minimise uncertainties on the deconvolved derivatives. This was done by numerically simulating the behaviours of a number of interfering, multiply-fractured, horizontal wells (from 2 to 8) for various rate sequences. The impact of including non-interfering wells in the multiwell deconvolution was also investigated.

It was found that the accuracy of the multiwell deconvolution process was very much dependent on the rate sequence: producing and shutting in wells sequentially provides better results that having the same rate sequence on all the wells. In addition, to minimize errors on the derivatives, the start of interference effects should be evaluated correctly and non-interfering wells should be excluded from deconvolution. Both require a good understanding of the reservoir.
The Impact of Crude Oil Induced Wettability Alteration on Remaining Saturations of CO2 in Carbonates Reservoirs: A Core Flood Method
Authors: Al-Menhali Ali , Krevor Samuel
Published: April 2016

Oil is an essential commodity in modern economies but the magnitude of carbon emissions associated with its consumption is significantly increasing the challenges of climate change mitigations. Carbon storage is well recognized as an important technology for CO2 emissions reduction on industrial scales. Observations and modeling have shown that residual trapping of CO2 through capillary forces within the pore space of saline aquifers, characterized as water-wet, is one of the most significant mechanisms for storage security and is also a factor determining the ultimate extent of CO2 migration within the reservoir. In contrast, most of the major CO2 storage projects in operation and under construction are in depleting oil reservoirs utilizing CO2 for enhanced oil recovery (EOR). Carbon utilization and storage has a significant energy and economic benefits and is considered as an important component in achieving the widespread commercial deployment of carbon storage technology. However, there are no observations characterizing the extent of capillary trapping of CO2 in mixed-wet carbonate systems, a characteristic of most conventional oil reservoirs in the world. In this work, residual trapping of supercritical CO2 is measured in water-wet and mixed-wet carbonate systems on the same rock sample before and after wetting alteration with crude oil. In particular, CO2 trapping was characterized before and after wetting alteration so that the impact of the wetting state of the rock is observed directly. A reservoir condition core-flooding laboratory was used to make the measurements. The setup included high precision pumps, temperature control, stir reactor, the ability to recirculate fluids for weeks at a time and an X-ray computed tomography (CT) scanner. The wetted parts of the flow-loop were made of anti-corrosive material that can handle co-circulation of CO2 and brine at reservoir conditions. The measurements were made while maintaining chemical equilibrium between the fluids (CO2 and brine) and rock phases to prevent reaction with the core sample and replicate conditions far away from the injection site. A novel core-flooding approach was used, making use of the capillary end effect to create a large range in initial CO2 saturation in a single core-flood.