bluuebunny/crossref_metadata_2025_split huggingface dataset:
Formation Induced Well Deformation
Authors: Skomedal Eiliv , Park Joonsang , Huynh Dat Vu , Choi Jung Chan 
Published: April 2019

Abstract
There are a lot of reports of formation induced damage of wells world-wide. Despite extensive literature on the subject, formation induced damage is not a standardized part of well design. One reason may be that the associated fundamental mechanism is not yet fully understood, which makes it difficult to implement in design rules. As a step towards practical design, this paper aims at improving the understanding of characteristic mechanisms of well formation interaction by analytical solutions to two simple cases. The first case considered is a vertical well in a compacting reservoir and is solved by elasticity theory. An elastic length parameter is derived, which is function of the axial stiffness of well and shear stiffness of formation. The well is then shown to follow the deformation of the compacting reservoir, with exception of a transient zone around the boundary to the overburden. The elastic length determines the size of this transient zone. Through the transient zone, the axial force reduces towards zero in the overburden. A learning is that in many cases it is sufficient to instrument the well casing or liner to measure reservoir compaction. The result also supports the finding that the high number of well damage in the deep overburden is due to another mechanism: shear deformation or slip of a weak plane crossing the well. This second case is also studied analytically yet based on plasticity theory. Input parameters to this model are shear and moment capacity of the well, shear strength of the formation and a load displacement characteristic of the formation. A general finding is that during such slip, the well is normally not able to resist, and it fails by exceeding the moment capacity at a distance from the shear plane.
The final and third case studied is ovalization of the cross section of a horizontal well due to pressure from the formation. This is a phenomenon occurring in salt and weak shale. It is a more complex interaction problem and a numerical simulation by finite element is used to solve it. A workflow is developed for an uncemented part of a horizontal well in a shale formation. Input parameters are in-situ stress, pore pressure and stiffness and strength of well and formation. Since the vertical stress is larger than the horizontal, the shear mobilization is largest to the side of the casing and shear failure starts there, initiating plastic deformation until contact and start of ovalization by reducing the lateral diameter of the well. By reduction of the mud pressure in the outer annulus, the contact area grows. Finally, the structural capacity of an ovalized casing with full formation contact is calculated. The formation is found to have some supporting effect and the resulting capacity is higher than the capacity of an ovalized casing without formation support.
Orientation Criteria of Fracture Initiation in Poroelastic Media: Application in Unconventional Reservoirs
Authors: Michael Andreas , Gupta Ipsita 
Published: April 2019

Abstract
Analytically-developed criteria are presented for the orientation of fracture initiation from horizontal wellbores drilled in porous-permeable (poroelastic) media, considering fluid infiltration. This involves drilling-induced tensile fractures (DITFs) from non-perforated wellbores and completion-induced hydraulic fractures (CIHFs) from perforated wellbores with cylindrical perforation geometry. Transverse CIHF initiation only occurs over a narrow wellbore pressure-at-breakdown window, while longitudinal initiation occurs at comparatively higher wellbore pressures. Nevertheless, transverse CIHF initiation occurs more frequently than transverse DITFs, because of the presence of perforation tunnels, which aid transverse fracture initiation.
Unlike for DITFs, the complex geometry of a perforated wellbore does not allow derivation of expressions for the exact solutions of the stresses inducing longitudinal and transverse fracture initiation. Thus, approximations implemented in the past for perforated wells in linearly-elastic media are extended to poroelastic media, deriving closed-form analytical solutions for the fracturing stresses to develop an orientation criterion for fracture initiation from perforated wellbores. This is useful for completion engineers; when targeting low permeability formations, wellbores must be made to induce multiple transverse fractures, as opposed to longitudinal fractures, which are more effective in higher permeability formations.
The region of the in-situ stress states where transverse initiation is promoted is shown in dimensionless plots for perforated and non-perforated wellbores. Graphical solutions of the resulting criteria are presented showing how various parameters affect the range of in-situ stress states in which transverse initiation is promoted; a rarity compared to longitudinal fracture initiation in the case of DITFs, unlike for CIHF where transverse initiation occurs more frequently. The criteria are finally implemented to seven prolific shale plays; Barnett, Bakken, Fayetteville, Haynesville, Niobrara, Marcellus and Vaca Muerta assessing the conditions under which transverse CIHF initiation occurs.
Characterization of Multiple Transverse Fracture Wells Using the Asymptotic Approximation of the Diffusivity Equation
Authors: Malone Andrew , King Michael J. , Wang Zhenzhen 
Published: April 2019

Abstract
Rate transient analysis using log-log plots of rate-normalized pressure (RNP) and its derivative (RNP') versus material balance time have proven helpful in providing estimates of shale matrix permeability and SRV drainage volumes in multiple transverse fracture wells (MTFW's) (Samandarli et al. 2012). The calculation of these properties requires the accurate detection and definition of the "end of linear flow" (telf) – the time at which hydraulic fractures begin to draw down upon their neighbors, causing the onset of what Song and Ehlig-Economides (2011) have described as "pseudo pseudo steady state" flow. The definition of telf is currently ambiguous, and in this study, we quantify and clarify the numerical definition of telf and the physical mechanisms behind its use as a permeability and drainage volume estimator.
We have constructed an analytical model of MTFW's that accurately predicts individual fracture flow performance for both constant and variable rate and constant bottom hole pressure inner boundary conditions. Using this model, we can accurately compute the pressure disturbance and rate change seen at the whole well and for individual fractures to quantify the degree of interference between fractures for any number of parallel, equally-spaced, and equally-sized fractures. This model has been validated by simulation using a commercial simulator. With both this analytical model and a series of numerical simulations, we investigated the fundamental mechanisms of flow in MTFW's and how the estimation of telf may be improved.
Previous authors have represented the progression of flow regimes in MTFW's as a linear flow period that transitions to a pseudo steady state (or apparently boundary-dominated) flow regime. We show that the same flow response is exhibited by a fully-infinite linear system, calling into question the nature of the "stimulated reservoir volume" (SRV) as a bounded reservoir system. In addition, we show telf can be detected and interpreted as the beginning of the onset of this fracture interference using the "limit of detectability" concept.
A History Matching Approach to Estimate Caprock Morphology Parameters for CO2 Storage in Saline Aquifers
Authors: Ahmadinia Masoud , Shariatipour Seyed , Andersen Odd , Sadri Mahdi 
Published: April 2019

Abstract
To improve the reservoir simulation model, uncertain parameters such as porosity and permeability in the reservoir rock strata need to be adjusted to match the simulated production data with the actual production data. This process is known as History Matching (HM). In geological CO2 storage that is being promoted for use in depleted hydrocarbon reservoirs and saline aquifers, CO2 tends to migrate upwards and accumulate as a separate plume in the zone immediately beneath the reservoir caprock. Thus caprock morphology is of considerable importance with respect to storage safety and migration prediction for the purpose of long-term CO2 storage. Moreover, small scale caprock irregularities, which are not captured by seismic surveys, could be one of the sources of errors while matching the observed CO2 plume migration and the numerical modelling results (e.g. Sleipner). Thus here we study the impact of uncertainties in slope and rugosity (small scale caprock irregularities not captured by seismic surveys) on plume migration, using a history-matching process. We defined 10 cases with different initial guesses to reproduce the caprock properties representing an observed plume shape. The results showed a reasonable match between the horizontal plume shape in calibrated and observed models with an average error of 2.95 percentages
Evaluation of Environmentally Friendly Drilling Fluid Additives in Water-Based Drilling Mud
Authors: Al-Hameedi Abo Taleb , Alkinani Husam H. , Dunn-Norman Shari , Alashwak Nawaf A. , Alshammari Abdullah F. , Alkhamis Mohammed M. , Mutar Rusul A. , Ashammarey Alaa 
Published: April 2019

Abstract
Drilling wastes generated in large volumes is recognized to have many effects on the environment. Several techniques have been applied by the oil and gas industry to overcome the impacts of drilling waste on the environment, an example of these techniques is using environmentally friendly drilling fluid additives.
This work investigates the potential of using Fibrous Food Waste Material (FFWM) as an environmentally friendly drilling fluid additive. This material was prepared in-house. Experimental evaluation has been carried out to investigate the ability of FFWM to enhance several properties of water-based drilling fluid under two different pH conditions. The FFWM was first evaluated at 9.3 pH then the pH was increased using sodium hydroxide to 11.5. Several properties of drilling fluid were measured. The measurements included testing the rheological properties using viscometer, measuring the filtration using standard low-pressure low-temperature filter press, the pH using pH tester, and other important properties.
The findings of this work showed that FFWM in 9.3 pH environment reduced the fluid loss by 18% and 30% when 1% and 2% concentrations of FFWM were added, respectively. This reduction in fluid loss was along with forming a thin filter cake. The filter cake thickness of the reference fluid was decreased from 3 mm to 2.14 mm and 1.9 mm at 1% and 2% concentrations of FFWM. Additionally, FFWM resulted in increasing the plastic viscosity (PV) compared to the reference fluid by 33.33% at 1% and 2% concentrations. While the yield point (YP) was increased by 22.22% and 44.44% when 1% and 2% concentrations of FFWM were added, respectively. Both the initial and final gel strengths were increased by 27.27%, 44.44 %, 7.14% and 14.28% at 1% and 2% concentrations, respectively. Moreover, the results in 11.5 pH emphasized the efficient performance of FFWM, and it showed better improvement in the filtration specifications and the rheological properties. In other words, PV, YP, and gel strength were significantly increased; while the fluid loss was very low and the filter cake was very thin at 11.5 pH condition compared to 9.3 pH condition for the same concentrations, proving the ability of FFWM to perform better under higher pH condition.
The significant enhancement in the rheological and filtration properties, suggesting the applicability of using this additive as a rheology modifier and filtration control agent. These results showed the potential use of FFWM as an alternative for some of the toxic materials used today in the oil and gas industry. This work demonstrates that this additive will help to reduce both the impact on the environment along with reducing the cost of drilling fluid and drilling waste handling.
Assessing Waterflood Efficiency with Deconvolution Based Multi-Well Retrospective Test Technique
Authors: Aslanyan Artur , Grishko Fedor , Krichevsky Vladimir , Gulyaev Danila , Panarina Ekaterina , Buyanov Anton 
Published: April 2019

Abstract
A waterflood study has been performed on a heterogeneous oil deposit with a rising water-cut and production decline after 10 years of commercial production.
The objective was to analyze the efficiency of waterflood patterns across the field and suggest injection optimization opportunities.
The production is facilitated by ESP with Permanent Downhole Gauges (PDGs) which provides an opportunity to analyze the productivity index and cross-well interference.
The PDG analyzes was performed in PolyGon pressure modelling facility and followed Multi-well Retrospective Testing (MRT) workflow which is based on the mathematical procedure of multiwell deconvolution (MDCV).
MDCV trains the correlation between bottom-hole pressure (BHP) variations from PDG data records and rates variations from daily production history of a given well and other wells around it.
This provides a robust short-term predictor for production response for different rate/BHP scenarios and makes a basis for injection optimization opportunities.
MDCV allows reconstructing formation pressure and productivity index back in time, pick up the changes and understand if they were caused locally (by skin) or massively (by transmissibility).
The diffusion modelling of deconvolved data allows a robust quantification of some reservoir properties in cross-well intervals, such as the current drained volume around each well, potential drained volume (as if the offset wells are shut-down), apparent cross-well transmissibility, boundary types and compare them against the various geological scenarios and possible well-reservoir contact scenarios.
The quantitative analysis allows picking up anomalously high cross-well interference which may be caused by thin-bedding circuiting or induced fracture. It also provides a strong hint for thief-injection and thief-production in cases of poor cross-well interference.
Overestimation in Operators Budgets and Long-Term Forecasting; A Non-Operator Perspective
Authors: Leeftink Tom , Aramburo Velez Daniel , Godderij Raymond 
Published: April 2019

Abstract
EBN is the Dutch state energy company that is a large non-operating partner of over 10 different operators that produce from more than 200 on- and offshore assets with more than 850 projects defined on them. Estimating budget production, medium and long-term forecasts and its associated operating and capital expenditures are of vital importance to EBN. Larger companies with many assets and even more projects, at varying degree of maturity, have great difficulty to reliably predict an aggregated forecast.
Historically, EBN would copy and risk operator data, which led to continuous overestimation of both budget production and longterm forecasts. A straightforward correction method was developed; that consists of two parts: firstly, the budget production is set for all producing assets and projects by assessing technical, subsurface, infrastructural and human factors on the operator's fields and projects performance. Secondly, the medium and longterm forecast is delayed with 1 to 4 years for respective SPE PRMS resource classes "justified for development" to "project unviable" and the associated project forecasts are risked with a chance of development according to their subclasses of the contingent resource classes.
Data analytics on almost 10 years of reserve reporting according to SPE PRMS standards led to a straightforward solution to reduce short and medium-term forecasting error. The short-term absolute average error used to be 8%. Through the implementation of the new method, 7 years ago, the absolute average short-term forecasting error dropped to 4%. The long-term aggregated forecast, obtained by simply copying the operator data, resulted in an overestimation of up to 50% 5 years ahead. The overestimation was reduced to an absolute average error of 23% by an earlier correction method, which only used risking factors on contingent projects, but no time delay. This paper presents a new method, that uses both risking factors and time delays on the realization of projects. The method reduced the error in the long-term forecast to an uncertainty band of a few percent.
Various causes for the overestimation were identified. The budget production errors were primarily attributed to wrong uptime predictions. Longterm forecast errors are impacted by the overestimation of the number of executed projects, while the timing and performance of new projects affects both the short and middle term forecasts.
The solution presented is the first methodology for EBN that is able to predict aggregated forecasts of hundreds of projects of several operators with an accuracy within a 5% margin over a lengthy period. The described risking factors described, and delay times, are dependent on the portfolio maturity and investment climate. Historic data has to be utilized to determine these factors for your portfolio.
Thermally-Induced Secondary Fracture Development in Shale Formations During Hydraulic Fracture Water Invasion and Clay Swelling
Authors: Eveline Vena F. , Santos Laura P. , Akkutlu I. Yucel 
Published: April 2019

Abstract
Current trends in shale gas industry require an advanced-level understanding of fracturing water invasion into formation and the subsequent water-shale interactions. Previously, we studied osmosis and clay swelling effects on the permeability of the shale formation. Shale, with an average 50% clay content, could hold large cation-exchange-capacity and significantly improved membrane efficiency, which may promote swelling and changes in the stress. In addition, large temperature-gradient effects due to cold water contacting the formation has not been investigated in detail.
A new geomechanically-coupled reservoir flow simulator is developed, which accounts for cold freshwater imbibition, osmosis and clay-swelling effects on the formation permeability under stress. The model includes aqueous and gaseous phases with three components: water, gas and salt. Governing geomechanical equation includes pore-pressure as well as temperature gradients. Volumetric strain (porosity changes) is calculated as a function of the mean normal stress, pore pressure and temperature. Imbibition occurs in water-wet inorganic part of the matrix, in the micro-cracks. Osmosis and clay swelling effects develop when the imbibed water in the micro-cracks interacts with the saline water in clay pores, which acts as a semi-permeable membrane to the water and experiences pore (osmotic) pressure changes and swelling of the clay in the formation.
The effect of temperature is pronounced early during the shut-in when imbibition of cold water takes place rapidly. Cold water introduces a low-stress region near the fracture due to thermal expansion effect and pore pressure buildup. We used a criterion and discuss the potential for fracturing. It is anticipated that the fracturing develops during forced imbibition of cold water given that a large difference exists between the injected water and the formation temperatures.
Multiscale Integration for Karst Reservoir Flow Simulation Models
Authors: Correia Manuel , Hohendorff João , Schiozer Denis 
Published: April 2019

Abstract
The significant oil reserves related to karst reservoirs in Brazilian pre-salt field adds new frontiers to the development of upscaling procedures to reduce time on numerical simulations. This work aims to represent karst reservoirs in reservoir simulators based on special connections between matrix and karst mediums, both modeled in different grid domains of a single porosity flow model. This representation intends to provide a good relationship between accuracy and simulation time.
The concept follows the Embedded Discrete Fracture Model (EDFM) developed by Moinfar, 2013; however, this work extends the approach for karst reservoirs (Embedded Discrete Karst Model - EDKM) by adding a representative volume through grid blocks to represent karst geometries and porosity. For the extension of EDFM approach in a karst reservoir, we adapt the methodology to four stages: (a) construction of a single porosity model with two grid domains, (b) geomodeling of karst and matrix properties for the corresponding grid domain, (c) application of special connections through the conventional reservoir simulator to represent the transmissibility between matrix and karst medium, (d) calculation of transmissibility between karst and matrix medium.
For a proper validation, we applied the EDKM methodology in a carbonate reservoir with mega-karst structures, which consists of non-well-connected enlarged conduits and above 300 mm of aperture. The reference model was a refined grid with karst features explicitly combined with matrix facies, including coquinas interbedded with mudstones and shales. The grid block of the reference model measures approximately 10 × 10 × 1 meters. For the simulation model, the matrix grid domain has a grid block size of approximately 100 × 100 × 5 meters. The karst grid domain had the same block size as the refined grid. Flow in the individual karst grid domain or matrix grid domain is governed by Darcy's equation, implicitly solved by simulator. However, the transmissibility for the special connections between karst and matrix blocks is calculated as a function of open area to flow, matrix permeability and block center distance. The matrix properties were upscaled through conventional analytical methods. The results show that EDKM had a considerable performance regarding a dynamic matching response with reference model, within a reduced simulation time while maintaining a higher dynamic resolution in the karst grid domain without using an unconstructed grid.
This work aims to contribute to the extension of EDFM approach for karst reservoirs, which can be applied to commercial finite-difference reservoir simulators and it presents itself as a solution to reduce simulation time without disregarding the explicit representation of karst features in structured grids.