bluuebunny/crossref_metadata_2025_split huggingface dataset:
Field Proven Solutions to the Challenges of Centralizing Solid Expandable Casing
Authors: Farley Douglas , Scott Thad 
Published: October 2011

Abstract
During well design and construction, the cementing of tubulars into the wellbore, referred to as primary cementation, has always been a critical step because the introduction of cement into the annulus between the tubular and open hole provides zonal isolation. It is well documented by API, SPE and other industry publications that achieving a good cement bond depends on the proper selection and placement of centralizers onto the pipe being cemented. In addition, getting the pipe to total depth (TD) is one of the most important objectives in the well construction process. Proper placement of centralizers drastically reduces the effects of differential sticking of slick OD tubulars when running across permeable formations and increases the chance of getting to TD. Once at TD, centralizers play a very important role by aiding in mud removal, which allows the cement to flow into the proper position with minimal channeling.
Solid expandable liners are most often run without centralization due to the very nature of expanding tubulars and the effect that the centralizers would have on the expansion forces. Another contributing factor is the tight clearances between the host casing and the expandable tubulars that are present in many applications. Adding to these challenges is the need for proper standoff to aid mud removal in the underreamed hole section in which the expandable tubulars are deployed. Solid expandable liners provide a drilling hazard mitigation technique covering pressure anomalies in the wellbore and their use in horizontal wells for maximum oil recovery furthers the importance of centralization for drag reduction, zonal isolation and the prevention of differential sticking.
In this paper the authors will review the cementing process and the problems associated with centralizers and explore several novel, field-proven and developing approaches to centralizing solid expandable pipe using both positive standoff and bowspring centralizers.
Advanced Upscaling For Kashagan Reservoir Modelling
Authors: Panfili P. , Cominelli A. , Calabrese M. , Albertini C. , Savitskiy A. , Leoni G. 
Published: October 2011

Abstract
The Kashagan field is a huge carbonate formation located 4.5 km below the North Capian sea bottom. The reservoir is saturated by over pressured light oil and the development is based on first contact miscible gas injection.
The reservoir is highly stratified, with a fine sequence of depositional cycles and long range lateral correlations. Three porosity systems, matrix, karst and fractures can be organized in two main environments: a massive, low permeability, matrixlike inner platform and a highly fractured/karstified rim.
The reservoir geology is modelled by means of massive geological grids consisting of tens of millions of cells, with vertical spacing of one meter or even less to account for high order depositional cycles. Fine scale geological grid cannot be used to run compositional simulations and much coarser grids, where hundreds of geological layers are lumped in few tens of dynamic layers, are used by reservoir engineers. To minimize errors due to the coarse scale, an average lateral spacing of 250 m × 250 m is used for both simulation and geological grid, but nonetheless upscaling remains a challenge. Traditional permeability (k*) upscaling methods, including flow based methods, overestimate Kashagan field/wells production and injection potentials.
We implemented a methodology where the outcome of the upscaling are effective transmissibility (T*) instead than k*. T* upscaling has been proposed in the past as an alternative to k* upscaling, but it is neither part of commercial work-flows nor widely accepted in the reservoir modeling community. In our T* upscaling the solution of local flow problems around coarse cell interfaces is used to compute coarse transmissibility. T* and k* upscaling were compared by simulating both single phase and gas injection problems, including platform and rim, using the results of fine scale simulation as reference. We considered single porosity simulations with geological grid populated by only matrix (first medium) and karst+fracture (second medium) properties and dual porosity/dual permeability simulations encompassing both media. Contrary to k* upscaling, T* based coarse simulations perfectly replicate fine scale field and wells injection/production potentials.
Using T* upscaling as cornerstone for Company activities on Kashagan, we can run coarse scale full field simulations in few hours without loss of consistency with the results provided by weeks-long, often unpractical, fine scale simulations. On the contrary, the inaccuracy of k* upscaling would have required much finer and computationally expensive simulation grids together with the implementation of ad-hoc multi-phase upscaling.
Field Development Optimization with Subsurface Uncertainties
Authors: Litvak Michael , Onwunalu Jerome , Baxter Josh 
Published: October 2011

Abstract
This paper outlines a framework for simultaneous optimization of a broad range of field development decisions with subsurface uncertainties.
We optimize discrete and continuous decision variables such as the number of production or injection wells, their locations, perforation intervals, drilling schedules, well rates, etc. As a novel approach, we include additional categorical variables such as depletion strategy, well pattern, or facility size in the optimization process. We consider a limited number of discrete scenarios for each categorical variable (e.g., primary depletion, gas injection, or water injection as three development scenarios).
Field development constraints on well locations, rig schedules, economic risks etc. are incorporated in the optimization. Hydrocarbon recovery or some economic indicator can be used as the objective function for the optimization and applied for ranking the field development options.
Subsurface uncertainties are represented by incorporating multiple reservoir models in the optimization process. Ideally, all reservoir models in the ensemble should be evaluated for every considered field development option to define cumulative probability functions. However, this would make CPU demands very large in some cases. We propose two effective approaches to reduce CPU requirements: (1) one reservoir model is run to test the optimization criterion, and the remaining models are only run if the objective function is significantly improved; or (2) a novel application of a statistical proxy procedure to define a subset of the reservoir model ensemble that is run during the optimization cycle. The efficiencies gained with these techniques allow us to incorporate the additional decision variables in the full optimization process.
Our results indicate that the proposed algorithms sufficiently reduce CPU requirements to effectively handle field development optimization problems with many reservoir models representing subsurface uncertainties. The algorithms have been effectively applied in many fields for simultaneous optimization of well placement, drilling schedule, well production/injection rates, perforation strategy, injection strategy, and facility modifications. They have also been successfully applied in giant oil/gas fields optimizing general field development scenarios.
Well Completion Design Using High-Performance Passive Inflow Control Devices with Selective Isolation Capability
Authors: Coronado Martin P. , Peterson Elmer R. , Garcia Luis A. , Garcia Gonzalo A. 
Published: October 2011

Abstract
In long horizontal wells, oil production rate is typically affected by the reservoir heterogeneities, heel-to-toe effect and mobility ratio. The resulting imbalanced production profile may cause early water or gas breakthrough into the wellbore. Once coning occurs, well fluid production may be severely decreased due to limited flow contribution from the toe or from reservoir areas with high flow resistance in the porous media. To eliminate this imbalance, passive inflow control devices (PICDs) are placed in each screen joint or inflow point to balance the production influx profile across the entire lateral length and compensate for permeability variation.
PICD performance in producer (oil, gas, and high gas/oil ratio environments) wells under different operational conditions will be presented to show the technical benefits of this technique as well as their improved recovery efficiencies when compared to non-PICD completions. The quantification of the benefits of this completion technique was performed using a fully integrated reservoir simulator where the PICD flow performance characteristic (as a function of fluid properties and geometry), well completion description (packers, blank pipe, gravel pack, annulus flow, etc.) and reservoir simulation are considered. The latest-generation PICD design incorporates an integral sliding sleeve which allows selective isolation of portions of the wellbore during the course of a well's life. Shutting off whole sections that have unacceptably high water and/or gas production using the latest PICD feature is also modeled to show improved recovery performance.
This paper details the development of the latest-generation PICD design concept which provides the ability to isolate zones selectively as sections of the completion become uneconomical. Experience from the initial field installations of this new technology will also be discussed.
Analysis of Calibration Materials to Improve Dual-energy CT Scanning for Petrophysical Applications
Authors: Ayyalasomayajula Krishna K. , McIntyre Dustin L. , Jain Jinesh C. , Singh Jagdish. P. , Yu-Yueh Fang , Siddiqui Shameem 
Published: October 2011

Abstract
Dual energy CT-scanning is a rapidly emerging imaging technique employed in non-destructive evaluation of various materials. Although CT (Computerized Tomography) has been used for characterizing rocks and visualizing and quantifying multiphase flow through rocks for over 25 years, most of the scanning is done at a voltage setting above 100 kV for taking advantage of the Compton scattering (CS) effect, which responds to density changes. Below 100 kV the photoelectric effect (PE) is dominant which responds to the effective atomic numbers (Zeff), which is directly related to the photo electric factor. Using the combination of the two effects helps in better characterization of reservoir rocks. The most common technique for dual energy CT-scanning relies on homogeneous calibration standards to produce the most accurate decoupled data. However, the use of calibration standards with impurities increases the probability of error in the reconstructed data and results in poor rock characterization. This work combines ICP-OES (inductively coupled plasma optical emission spectroscopy) and LIBS (laser induced breakdown spectroscopy) analytical techniques to quantify the type and level of impurities in a set of commercially purchased calibration standards used in dual-energy scanning. The Zeff data on the calibration standards with and without impurity data were calculated using the weighted linear combination of the various elements present and used in calculating Zeff using the dual energy technique. Results show 2 to 5% difference in predicted Zeff values which may affect the corresponding log calibrations. The effect that these techniques have on improving material identification data is discussed and analyzed. The workflow developed in this paper will translate to a more accurate material identification estimates for unknown samples and improve calibration of well logging tools.
Utilization of Simple Fluids and Proppant Combined with Design Optimization Yields Outstanding Results in New Mexico Yeso-San Andres Oil Play
Authors: Ely John W , Jacoby Mark 
Published: October 2011

Abstract
In this paper we will describe fairly simplistic completion techniques which have dramatically changed the economics of completion in the Yeso and San Andres formations in southeastern New Mexico. The design optimization process will be described and comparisons made with offset operators for several years of production.
For many years the standard completion technique for the Yeso and other carbonate formations in Southeastern New Mexico was the use of large volumes of hydrochloric acid. The acid was sometimes heated, sometimes gelled. The acid was combined with various diverting aids to achieve what was considered excellent stimulation. In 2006 it was decided to reevaluate stimulation procedures and the oil company decided to use a similar process being utilized in Shale plays and many unconventional reservoirs. The Yeso and San Andres, with some natural fracturing and most of other criteria needed for successful use of what is termed "Waterfrac Sweep", were considered good candidates. This process uses only water and small proppant concentrations pumped at a high rate. The process has found success in virtually every shale play in the US as well as many conventional reservoirs such as the Granite Wash, Cotton Valley, Mesa Verde, Travis Peak, Atoka, and Olmos.
The paper will document the results of more than 100 fracs showing long term production data and comparisons to offset operators using more complex and more expensive systems. We will go through the completion process as it was used in large casing, thus in many instances totally eliminating the need for friction reducers. Very minimal chemicals are used plus proppant sizes no larger than 40/70 in concentrations not exceeding 2.5 pounds per gallon. Based on oil production data we feel infinite conductivity production is being achieved through propped open fractures instead of proppant packs.
There are countless naturally fractured carbonate reservoirs throughout the world that can benefit from this very straightforward stimulation procedure.
Reservoir Simulation: A Reliable Technology?
Authors: Lee W. J. , Sidle R. E. , McVay D. A. 
Published: October 2011

Abstract
Under pre-2009 SEC reserves reporting guidance, filers with the SEC had difficulty in persuading the SEC staff that reservoir simulation met the ‘reasonable certainty’ standards required to classify resources as proved reserves. With the modernization of the SEC's reserves reporting rules, ‘reliable technology,’ including computational methods, is allowed to establish the certainty level required for reporting reserves of any category. However, important questions arise: can we consider reservoir simulation to be a reliable technology? If so, what conditions must be satisfied to establish reliability? This paper concludes that simulation is indeed a potential reliable technology when we can demonstrate that it satisfies the criteria of consistency and repeatability, difficult criteria to satisfy for a computational method. The paper also concludes that the reserves analyst can demonstrate when simulation is reliable by proceeding through the steps in the scientific method outlined by Sidle and Lee (2010a) which provide guidelines to establish that a particular technology in question is consistent with the definition of a reliable technology.
At the reasonable certainty level required for proved reserves, we must demonstrate with empirical evidence that estimates of EUR based on simulation are much more likely than not to increase or remain constant as more historical data become available. For 2P (proved plus probable) reserves, we must demonstrate that EUR forecasts are as likely as not as more reservoir performance data become available, and for 3P reserves, EUR forecasts must remain possible though not likely. Empirical evidence that the required level of certainty has been achieved can come from either ‘hind-casting’ (successfully predicting the future based on only a portion of historical data) or from demonstrated success from applying the same simulation technology in analogous reservoirs, in which the same level of rigor was applied to ensure that the geological model or models used as the basis for simulation is appropriate and that it honors all available information.
When the industry broadly accepts reservoir simulation as a reliable technology (when applied appropriately) suitable for use in reserves disclosures and when it provides persuasive arguments about reliability to regulatory agencies, the interests of all stakeholders in reserves disclosure efforts will be enhanced.
Improved Estimation of Permeability from Joint Inversion of Time-Lapse Crosswell Electromagnetic and Production Data using Gradient-Based Method
Authors: Liang Lin , Abubakar Aria , Habashy Tarek M. 
Published: October 2011

Abstract
Formation permeability is one of the most important parameters for reservoir modeling. There is a high degree of uncertainty associated with the estimation of permeability using the conventional history matching, which adjusts the model to only fit the production data. In this paper, we present an approach to improve the estimation of permeability by history matching time-lapse crosswell electromagnetic and production data simultaneously. A multiphase fluid-flow simulator is used to calculate the time dependent bottomhole pressure at the wells as well as the temporal and spatial distributions of water saturation and salt concentration in the reservoir. The latter ones are transformed into the formation resistivity using a resistivity-saturation formula. A 3D finite difference electromagnetic solver is used to simulate the crosswell electromagnetic data. A regularized Gauss-Newton approach is then used to update the permeability in an iterative fashion until achieving a good match between the simulated and the measured data. In the inversion process, the derivatives of production data with respect to permeability are computed using the gradient simulator method, and the derivatives of electromagnetic data with respect to permeability are computed using the adjoint method and the chain rule.
Demonstrating Reasonable Certainty under Principles-based Oil and Gas Reserves Regulations
Authors: Sidle R. E. , Lee W. John 
Published: October 2011

Abstract
Historically, oil and gas reserves definitions have included the term "reasonable certainty" when describing the standard of high confidence/low uncertainty for a conservative estimate of future recovery from an accumulation. In 2008, the U.S. Securities and Exchange Commission (SEC), one source for such definitions and regulations, changed its rules on oil and gas reserves, and moved from a more rules-based approach to a more principles-based approach. While the SEC regulations both before and after this change incorporated the term "reasonable certainty", the philosophical change from rules-based to principles-based regulation puts more responsibility on the reserves evaluator to understand the uncertainties in the reserves estimation and to "get it right".
This paper examines the stated definition of reasonable certainty as well as the effective definition based on how the regulations were interpreted under the prior rules-based system. Examples of prior methods of regulatory controls, under a rules-based system, that no longer fit under a principles-based system are noted. The paper then examines the current definition. The overprint of a principles-based regulatory system must be considered to understand how such an approach will impact the effective definition under the current rules. The insights from the financial and legal communities are examined for their learnings where other forms of regulations underwent this same philosophical change. This examination describes how rules-based systems are more "input control" focused, while principles-based systems focus more on "outcomes".
Next the paper suggests how the reserves evaluator should apply this understanding of the new principles-based rules. The evaluator is now more responsible to understand the range of uncertainty in reserves estimates and to ensure that the outcome (the proved reserves estimate) satisfies the regulations. Also the paper discusses key tests to demonstrate that the correct outcome, a reasonably certain volume, has been achieved. After 30 years of well-established practices, the responsible reserves evaluator has examined changes as they evolved in then-current regulation text. Now the evaluator needs to additionally consider changes based on the implications of principles-based regulations.
Generalization of Dual-Porosity-System Representation and Reservoir Simulation of Hydraulic Fracturing-Stimulated Shale Gas Reservoirs
Authors: Du C. Mike , Zhan Lang , Li James , Zhang Xu , Church Stefan , Tushingham Keith , Hay Brad 
Published: October 2011

Abstract
Recently, we have developed a new methodology to model hydraulic fracturing-induced fracture networks and subsequently simulate a shale gas reservoir as a dual-porosity system. The reservoir geological, geophysical and petrophysical characteristic data are integrated to build geological framework and property models. Microseismic responses are used to delineate stimulated reservoir volumes. Microseismic events and/or natural fracture intensity are utilized to estimate the initial intensity of this induced fracture network. The fracture intensity is further calibrated using hydraulic fracturing job data and reservoir geomechanical properties through a fracture propagation mechanism.
In this paper, we show a significant extension of the modeling methodology to handle more general scenarios of stimulated shale reservoirs. We introduce a superposition technique to process the overlapping of microseismic mapping responses from different stages of "simul-frac" and/or "zipper-frac" operations in a single well or in multiple wells. The improved method takes into account different fracture network geometries. Various models for volume expansion by stimulation are investigated for proppant placement estimations. In the ideal viscous fluid-proppant transportation scenario, proppant and fracture conductivity distributions can be calculated with mass conservation corresponding to different fracture network geometries and volume expansion models. Both fracture intensity and fracture network conductivity are used to create dual porosity simulation model inputs. Considering that for most shale gas wells there is no microseismic data, we introduce a modeling procedure incorporating treatment data and geomechanical parameters in which the fracture network geometry can be specified based on well completion data and field experience. We also present the general workflow through a demo case from data input, fracture network geometry configuration, calibration and calculations, and output of dual-porosity model parameters for reservoir simulation. This extended methodology can be efficiently applied not only to modeling of singlewell shale gas reservoir but also to modeling of multiple wells where their drainage volumes are inter-connected. A field example demonstrates the applications of the new modeling methodology, which provides a unique, effective means for modeling and simulation study as well as history-matching calibration of stimulated shale gas reservoirs.