bluuebunny/crossref_metadata_2025_split huggingface dataset:
Automated Workflow for Real-Time Management in a Large Carbonate Field
Authors: ALNakhli Maithem M. , AlMousa Talal S. , Al-Nuaim Ahmad , Dallag Mohammed 
Published: September 2015

Abstract
Managing an oil and gas reservoir requires the integration and analysis of several data elements, including reservoir, well, and production data from multiple sources. Quick and efficient access to this data will allow engineers to concentrate their efforts on the important tasks of analysis and decision making, to improve reservoir and field performance.
This paper presents an overview of the implementation of an automated workflow designed to support the management of a Saudi Arabian reservoir, by integrating real-time production data with other data elements. The workflow and techniques used require specialized engineering processes to fully understand the reservoir behavior and associated parameters to identify wells with anomalous behavior1.
Among the solutions provided in this workflow is a system for real-time data retrieval, visualization, and analysis of reservoir production performance. This is achieved by linking dynamic surveillance processes with real-time data, and allowing data to be provided in real-time at the engineer's desktop. To provide a coherent explanation of the production behavior, multiple analysis processes and tools were used. These included a workover candidate selection system, decline curve analysis, and heterogeneity index analysis.
The workflow also included mapping and quality control tools to flag out data outliers. In addition, alarm systems were included to alert the engineer when sudden changes in reservoir performance occur in the field. The implementation of this workflow has resulted in considerable time savings, with pertinent data being automatically updated and used in the analysis, as opposed to manual processing, leading to improved efficiency in field management practices. The workflow has been deployed as an application of the Intelligent Field concept in a carbonate field in Saudi Aramco.
Sustainable Flow Back and Produced Water Treatment Using A Next Generation ElectroOxidation Reactor
Authors: Fraim Mike , Jakhete Sanjeev 
Published: September 2015

Abstract
Advances in electronics and materials technology have enabled fundamental changes in electro-oxidization reactor designs, significantly improving their performance, safety, and enabling dramatic treating cost reductions. Theoretical basis and field results are presented demonstrating in-situ generation of multiple oxidants using simply electricity and produced water without addition of hazardous reagents or oilfield chemicals. These oxidants are shown to be extremely effective biocides for bacteria disinfection, electrochemical precipitation is shown to reduce the scaling tendencies of the treated water for fracture treatment and water recycle or water injection. Creation of the ferrate ion on the anode side of the electrode surface inactivates the current borate ion concentration in the treated water so that it will not flash cross-link the added polymer for the hydraulic fracture treatment.
Estimation of Fracture Volume Between Well Pairs Using Deuterium Tracer
Authors: Leong Y. , de Iongh J. E. , Bähring S. , Tuxen A. K. , Nielsen T. B. 
Published: September 2015

Abstract
Short-circuit connections between injectors and producers resulting from induced or natural fractures in tight chalk reservoirs can divert the injection water resulting in poor sweep efficiency and early water breakthrough in producers. The overall impact is a significant reduction in oil recovery. Curing of these connections can be achieved through the application of a chemical conformance treatment aimed at plugging off the fracture and shutting the connected zone. Knowing the volume of the fracture is essential for such a conformance treatment, since it determines the amount of conformance chemical that should be injected. If too little material is pumped, the fracture will not be effectively closed, and if too much material is pumped, there is a risk of contaminating the connected well. However, the fracture volume estimation can be challenging due to the uncertainty of the fracture geometry.
Deuterium tracers offer a simple, quick and environmentally friendly method to estimate the volume of the fracture. The method was successfully employed on an injector/producer pair with a known fracture connection in the Danish North Sea. A deuterium tracer was selectively injected at a constant rate via coil tubing (CT) into the connected zone in the injector, and the producer was sampled from the wellhead. With the exception of the fracture volume, all other volumes (and therefore transit times) within the deuterium tracer injection path are known. Based on the deuterium's arrival time, the fracture transit time and therefore volume can be calculated.
The use of heavy water (D2O) as a chemical tracer allows DTI to conduct the tracer operation with real-time offshore analysis of the tracer breakthrough. The results obtained were subsequently applied to adjust the injection time and volume of the cement during the operation to cement the fracture.
Successful Case History of Drilling Through Major Loss Zone Using MPD/PMCD Techniques on a Santos Basin Well
Authors: Tomita R. A. , Schnitzler E. , Destri J. F. , Da Silva P. H. , Brasiliense N. R. , Fernandes A. A. , Gozzi D. S. , Da Silva T. Pinheiro , Kozlov A. 
Published: September 2015

Abstract
The development of the production phase of pre-Salt fields in Santos Basin have been facing many challenges, one of them is the occurrence of massive fluid losses during drilling, completion and evaluation operations. One possible solution to drill in this scenario is the usage of the Managed Pressure Drilling (MPD) techniques to minimize fluid loss and, in cases of massive losses, the use of the Mud Cap Drilling technique.
This paper presents a case study of the drilling operations on a Santos Basin well that had major losses while using conventional drilling technique hence unable to reach all objectives. The well was successfully reentered using MPD/PMCD to successfully reach target reservoir and the details of the solution to reentry using MPD/PMCD and its successful results is presented
It is described the use of MPD variants including the first use of PMCD on a DP rig on an offshore well in Santos Basin. MPD/PMCD proved an enabling technology when reentering a reservoir with major losses and absent drilling window. Design, execution and results of successful operations are covered.
Sand Control Screen Erosion: Prediction and Avoidance
Authors: Procyk Alex , Gou Xinjun , Marti Srinagesh K. , Burton Robert C , Knefel Markus , Dreschers Daniel , Wiegmann Andreas , Cheng Liping , Glatt Erik 
Published: September 2015

Abstract
Erosion of sand control screens in oil and gas wells can lead to catastrophic completion failures, substantial production losses and damage to downstream facilities. Screen erosion can be caused by a number of completion design and environmental factors. However, the dominant failure mechanism is production of small solids through the screen openings, leading to development of localized high-velocity hot spots in the screen filter media and subsequent failure of the media.
The current work discusses a detailed screen erosion study conducted to evaluate screen flow parameters leading to erosion and to provide safe operating guidelines for wells completed using cased hole perforated frac-pack (CHFP) and cased hole perforated gravel-packed (CHGP) completions with premium wire-mesh sand control screens.
The erosion study consisted of both experimental work to determine erosion damage in screen samples and computational fluid dynamic (CFD) simulations to help visualize particle flow paths through the metal-mesh sand control media and determine local flow velocities and erosion-induced wear patterns.
The experimental erosion tests and CFD modeling were performed on a specific screen configuration used in a number of subsea gas wells subject to high velocity flow conditions and associated high screen erosion potential. An empirical erosion model was then developed to translate short-term, high-velocity laboratory test results into field erosion predictions and well flow guidelines to minimize erosion potential.
This paper presents results of the experimental work and associated CFD modeling as well as completion flow guidelines developed for field operation of subsea gas wells.
Engineered Shale Completions Based On Common Drilling Data
Authors: Logan W. D. 
Published: September 2015

Abstract
Current best practices in North America's shale basins deliver inconsistent production results because of a lack of reservoir understanding along the lateral. Reservoir data is difficult and expensive to obtain in horizontal sections; therefore, most completions are designed geometrically, with little or no concern for reservoir heterogeneity. This leads to dramatic variability in productivity between neighboring wells, often described as the statistical nature of the play.
In this study, we demonstrate a reliable, cost effective methodology that empowers shale operators with reservoir data on every well. This technique will enable operators to engineer their designs by using reservoir data on every completion, resulting in significant productivity improvement without any significant increased cost or inconvenience.
This methodology leverages commonly available drilling measurements (rate of penetration, weight on bit, rotational speed, hole diameter, flow rate, differential pressure and standpipe pressure) and mud motor parameters (Kn, Tmax, ΔPmax) to derive Mechanical Specific Energy (MSE), using well established algorithms. The MSE parameter is then shown to be a good proxy for Unconfined Compressive Strength, a valuable reservoir parameter commonly used in frac designs. The MSE drives a facies-based answer product that enables the operator to position perforation clusters so that they breakdown at a common treating pressure, resulting in uniform fracture treatment within each frac stage.
To date the technique has been applied successfully on over 60 wells. It is validated through comparison to openhole wireline logs and by comparing productivity to offsetting wells. The technique is shown to be superior to similar attempts done by using openhole wireline logs and production data confirms its accuracy and reliability. This study demonstrates that drilling data can be effectively used to derive reservoir parameters that lead to completion designs that produce superior production results.
This methodology is the first application of drilling data to derive reservoir parameters that are then used to engineer a completion design. The significance of this development cannot be overstated, since it provides shale operators with the guidance they need to intelligently engineer their completions. The end result is significant productivity increases without any associated cost or inconvenience.
Integrated Injection Modeling
Authors: Izgec Bulent 
Published: September 2015

Abstract
The success of a waterflood is mainly determined by the performance of injector wells. This work outlines a simple three-stage integrated workflow for optimizing injector well performance.
In the first stage of workflow, matrix injection, fracture propagation, and plugging periods are identified with advanced Hall plots. In the second stage, field reported pressures are matched with a full field thermal/ geomechanical simulator. The final stage consists of duplicating the characteristic advanced Hall plot patterns with the history matched simulation model. At this stage, the previously history matched model is further fine-tuned to duplicate the characteristic advanced Hall plot patterns that were generated with field data.
Once complete, this fine-tuned model helps us understand the changes in fracture gradient caused by depletion and cooling, the extent and direction of the fracture and the impact of water quality on the overall performance.
Progressive Royalty Framework for Oil and Gas Development Strategy: Lessons from Nigeria
Authors: Echendu Joseph C. , Iledare Omowunmi O. 
Published: September 2015

Abstract
Royalty is a mechanism by which mineral owners – usually host government – obtain upfront revenue as soon as production begins from a petroleum lease or block. It can be received in cash or in kind and represents a part of front-loaded cost of doing business; it is tax deductible in oil and gas tax calculations. Economic rents extracted through royalty payments are usually not based on profits. This dampens the progressiveness of a fiscal regime and would normally have effects on investments and resource development economics.
This paper presents a progressive royalty framework and investigates the impacts of the various kinds of royalty schemes on oil and gas development economics. The conducts and performances of fixed, jumping and/or sliding royalty schemes are evaluated. Further, the paper reviews the different sliding scale specifications in fiscal systems and recommends the optimal boundary to ensure efficiency and effectiveness. The proposed royalty scheme recommended in the Inter Agency Team (IAT) memorandum on the 2008 Petroleum Industry Bill of Nigeria (PIB 2008), which was tied to terrain, geology and value forms the basis for the royalty design and modeling analysis evaluated in this paper.
Logarithmic sliding scale royalty scheme is generally perceived to perform better than other schemes but our analysis shows that terrain and geology matter a lot. This implies that if the royalty scheme is tied to geology, then marginal field operators would prefer the linearly sliding scale mechanism to logarithmic scale. Flexibility to switch from one scheme to the other offers incremental fiscal regime progressiveness in the quest for efficient, effective, equitable, and ethical energy resource development.
The paper recommends the use of sliding scale royalty scheme as a progressive bidding parameter and subsequent rent extraction instrument. The uncertainty in oil prices and its plummeting trend – plausibly discouraging exploration and exploitation of the not-easy-to-find hydrocarbons – requires progressive royalty schemes to create an equitable performance outcomes for all stakeholders in the emerging new petroleum era.
Wellbore Stability of Deviated Wells in Depleted Reservoir
Authors: Li Xiaorong , Gray K. E. 
Published: September 2015

Abstract
Reservoir depletion alters formation pressure, far-field in-situ stresses, and stresses around the wellbore. All of these factors influence collapse and fracture gradients, and therefore the drilling mud weight window. For deviated wells in depleted reservoirs, this situation is even more complicated due to the effect of well inclination and azimuth on the mud weight window. Analytical model results are presented in this paper for mud weight window calculations, considering formation pressure depletion, initial in-situ stress ratio (SHmax/Shmin), well inclination and azimuth.
In-situ stresses change due to reservoir depletion are first determined from poroelastic theory, assuming the reservoir experiences vertical deformation, but no deformation in the lateral directions. Next, far-field in-situ stresses after depletion are transformed to a deviated wellbore with arbitrary well inclination and azimuth. Then, utilizing the Mohr-Coulomb shear failure criterion and tensile strength failure criterion, collapse and fracture gradients are calculated for various ratios of initial horizontal stress, degree of depletion, wellbore inclination, and azimuth. Finally, the sensitivities of collapse and fracture gradients relative to these factors are compared and discussed. The most problematic situation is to drill highly deviated or horizontal wells in reservoirs with large depletion along the maximum horizontal stress direction. In this case, fracture gradient can reach extremely low levels, resulting in very narrow drilling window and very small margin for mud weight adjustment. Drilling along or near the direction of minimum horizontal stress is preferred. An interesting finding in this study is that fracture gradient does not always decrease for deviated wells, which is contrary to common understanding that fracture gradient always decreases as the pore pressure gradient declines.
Self-Suspending Proppant Transport Technology Increases Stimulated Reservoir Volume and Reduces Proppant Pack and Formation Damage
Authors: Goldstein Brian , VanZeeland Alan 
Published: September 2015

Abstract
Self-suspending proppant technology, a hydrogel polymer wrapped around a sand or ceramic substrate, resists settling in a low-viscosity fluid to uniformly distribute proppant throughout the fracture. The fluid remains in-zone to increase the stimulated reservoir volume. With this new technology, oil and gas production increases.
This technology eliminates compromises the industry has faced for decades. Because proppant falls out of the fluid before reaching the fracture tip, engineers have had to increase fluid viscosity and/or pumping rates, in addition to decreasing proppant mesh size or proppant density. These compromises increase completions cost and reduce conductivity.
With self-suspending proppant technology, fluid sweeps are eliminated because proppant maintains efficient transport characteristics and forms a higher, more uniform settled bed height compared with proppant transported by conventional gel or slickwater fluid systems. Pumping time is reduced because of the higher capacity to carry proppant compared with slickwater. Fewer fluid additives are required because less fluid volume is needed.
In addition to better proppant transport, this technology reduces proppant pack and formation damage. After breaking the polymer system and during fluid flowback, little to no residue remains. Further, according to test results from an independent laboratory, this new technology does not damage the proppant pack and formation with fluid additives, resulting in maximum regain conductivity and retained permeability. Typical frac fluid additives that support proppant transport can damage proppant pack conductivity and formation permeability by as much as 70% and 60%, respectively (Bilden, Fletcher, Montgomery, Guillory, and Allen 1995).
Two field trials show how the application of self-suspending proppant technology can increase stimulated reservoir volume and increase well production. In a Mississippian Lime liquids-rich play, self-suspending-proppant-coated 20/40 Northern White sand increased 18-month cumulative BOE 45% compared with the uncoated 20/40 Northern White sand in the offset's conventional slickwater design.
In an Escondido formation gas play, an operator compared a 46% self-suspending proppant tail-in with a simplified slickwater design. The technology boosted 60-day gas production by more than 55% while decreasing pumping time and water consumption with fewer fluid additives.
The shear-resistant polymer ensures greater drainage by traveling farther in a thin fluid for a substantially increased propped fracture area. A clean polymer break leaves the proppant pack and formation without fluid damage so hydrocarbons can flow freely.
A Real Options Approach to the Gas Blowdown Decision
Authors: Thomas Philip , Bratvold Reidar B. 
Published: September 2015

Abstract
Many oil fields have gas caps or associated gas. The common approach for these fields is to continue to produce oil, whilst re-injecting any gas produced, for as long as it is profitable, and then produce gas. This approach is motivated by the belief that it will maximize the oil reserves and thus maximize the overall value of the field.
In this paper we show why maximizing the length of profitable oil production does not necessarily create the most value. The analysis also provides guidance and insight on operating decisions that would not be obtained through a more conventional approach.
In this paper we show how a real options valuation approach can be used to determine the optimal blowdown decision. The approach we take is to re-inject gas to maintain oil production only until the time it is more financially valuable to produce gas and thus blow-down pressure support for oil production. To model price uncertainty we use correlated two-factor price processes. We also consider, uncertainties in oil and gas reserves and production as well as in transition costs. The model is solved using the Least-Squares Monte Carlo simulation approach. We use a material balance simulator, which is embedded into the underlying model, to represent the oil and gas production.
We illustrate how the approach can be used to identify optimal blowdown time, and thus maximize value, for a North Sea based oil field with associated gas.
Our results indicate that the value-maximizing blowdown time is different than would be computed using traditional net present value. Furthermore, the approach we take in this paper yields a decision-policy “map” that indicates the optimal choice given the state of oil prices, gas prices, production rates, costs, and remaining reserves in any given year.
The results presented here are relevant and applicable to oil and oil/gas fields across the world. Calculating the optimal blowdown time is not straightforward as it is a function of the underlying uncertainties such as oil and gas prices, their co-variation, oil and gas reserves and production, blowdown costs, and technology improvements, and its calculation is not trivial. However, ignoring these uncertainties leads to sub-optimal blowdown decisions, resulting in significant value losses.
A Framework for Transparency in Drilling Mechanics and Dynamics Measurements
Authors: Macpherson John D. , Paul Pastusek , Behounek Michael , Harmer Richard 
Published: September 2015

Abstract
The use of real-time mechanics and dynamics measurements has expanded and evolved significantly in the last thirty years, enabling the safe and reliable drilling of complex wells. Unfortunately, these measurements are poorly defined, which inhibits straightforward analysis and hinders development of models, simulators and automation applications. Adoption of open measurement guidelines will provide the transparency required to improve the value of existing measurements and accelerate the development and adoption of enhanced applications and automation.
Mechanics and dynamics measurements currently can be processed and transmitted from downhole in near real-time and then merged with other surface measurements. Optimization of the drilling process uses these combined measurements for monitoring, advising and control, thereby delivering a quality borehole as planned, in a safe and reliable fashion. Processing includes real-time filtering, mathematical modeling, and simulation, which are significant parts of any systems approach.
There are currently multiple methods used to quantify downhole and surface vibrations, displacements, and forces. Tools use dissimilar sensor and processing configurations, so they yield significantly different data. Regrettably, these different measurements are given the same name, and published descriptions often do not include the details required to understand and properly utilize the data. Examples of key information include sensor characteristics, sensor arrangement, bandwidth, and signal processing. Guidelines are suggested to resolve this state of confusion, including: terminology describing each drilling mechanics and dynamics sensor, configuration, and measurement; and metadata describing how a data value is derived, filtered, processed, transmitted and stored.
This paper examines and defines drilling mechanics and dynamics measurements. It recommends measurement practices and good processing techniques of these measurements, with examples, and presents a recommended open measurement framework. Adoption of this framework will resolve the current state of confusion and uncertainty, enable all parties to develop monitoring, advising and control applications that use these data, and help lower well costs and improve borehole quality.