bluuebunny/crossref_metadata_2025_split huggingface dataset:
Water-Soluble Sodium Silicate Gelants for Water Management in Naturally Fractured Carbonate Reservoirs
Authors: Hatzignatiou Dimitrios G. , Giske Nils H. 
Published: April 2016

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.