bluuebunny/crossref_metadata_2025_split huggingface dataset:
Enhancing the Effectiveness of Long Horizontal Water Injection Wells with ICD/SSD Technology – Design, Simulation, and Installation
Authors: Kuck Marc , Holderman Luke , Brown Dan , Thornton Kim , Kuo Nicholas 
Published: October 2012

Abstract
Horizontal completions have continued to increase in length and complexity, which has made their design considerably more challenging for completion engineers. Eni Petroleum's Nikaitchuq Field in Alaska is a prime example of how the increases in wellbore length have affected the use of traditional technologies. Previously, these completions would use horizontal water injection to drive the horizontal producers; however, with the increased wellbore lengths, Eni Petroleum was facing challenges that were due to the completion criteria exceeding the capabilities of the traditional injection/production completion scenarios.
Nikaitchuq is a low pressure, low temperature, high-oil-viscosity reservoir in which Eni Petroleum must drill shallow wells with long lateral sections. This trajectory requires high torque completion equipment in order to assure that equipment will reach total depth (TD). With these extended horizontal lengths, delivering tools to depth and uniformly driving a cold viscous hydrocarbon is extremely difficult with the use of traditional technology.
An innovative solution was designed to meet these challenges. By coupling adjustable inflow control devices, sliding sleeve devices, and low-temperature water-swelling packers, Eni Petroleum was able to balance their injection profile without complex and costly equipment. Now, Eni is able to shut off individual injection zones in the event of reservoir formation breakdown that results in problems in injector/producer communication.
Using reservoir simulation software, the service company's new completion design can maximize productivity. The ICD's can be adjusted based on reservoir simulations, and the tools can be run to depth with the newly developed completion design. In the trial run by Eni, injection was brought on line, which enabled the swelling packers to reach full diameter. Because of this success, the completion plan was executed on additional wells in the field. This paper will discuss the completion used and how a simple, repeatable, completion design was capable of successfully overcoming a complex problem.
Production Array Logs in Bakken Horizontal Shale Play Reveal Unique Performance Based on Completion Technique
Authors: Boyer Robert , Findlay II Clyde , Suparman FNU , Sudija Jaja , Reyes Robert 
Published: October 2012

Abstract
ConocoPhillips drilled and completed three horizontal wells in the Bakken Shale, North Dakota in 2010; these wells contained between 33 and 40 stages. The lateral of each well consisted of a hybrid design using sliding sleeves in the toe- most half of the well and plugs/perforations for the heel-most half. Multiple completion techniques were pumped in an alternating pattern throughout the plug and perforation section of each well, and production array logs were deployed on coiled tubing in an attempt to determine fracture design best practices.
As one of the key parameters to horizontal well performance in the shale plays, fracture performance evaluation becomes the main objective. The flow contribution from each fracture stage was first determined from array production log interpretations in terms of the in-situ productivity index, which became the basis for fracture stage performance analysis. This paper also includes a discussion of the challenges associated with understanding the multiphase fluid flow behavior in horizontal wells.
The subsequent analysis of fracture performance was performed to relate the in-situ productivity index with other well parameters, such as well trajectory, fracture method, fluid and reservoir information around the well and the mud log information during drilling. Oil, gas, and water rates were generated for each stage and correlated to completion technique.
The final analysis was aimed to answer some of the questions about how certain fracture stages performed better in comparison to others. This analysis includes identifying parameters in favor of increasing fracture performance and defining the steps needed to deal with the challenges related to the geological nature of the field. The information from this integrated evaluation result was then used to define a better strategy to improve the well performance in the future drilling campaign and to optimize the commercial value of the field.
Reappraisal of the G Time Concept in Mini-Frac Analysis
Authors: Bachman R. C. , Walters D. A. , Hawkes R. A. , Toussaint Fabrice , Settari A. 
Published: October 2012

Abstract
Industry is currently using mini-frac analysis for the determination of fracture closure stress and after-closure reservoir properties. The foundation of all mini-frac analysis is the one dimensional Carter leak-off model, which leads directly to the concept of G Time. For 30+ years, G Time (or the G function) has played the dominant role for the determination of closure stress. The current norm uses combination G function and combination square root Δt plots for closure pressure determination. Each combination plot has three plotting functions associated with it. These combination plots also allow the identification of non-ideal behavior. Additionally, various log-log derivative techniques based on pressure transient analysis concepts have been developed to act as a guide for determining flow regimes and closure pressure. These PTA based techniques also allow the determination of after-closure flow regimes and properties. Concurrently, various specialized afterclosure plotting techniques have been developed for fracture/reservoir property determination.
Despite all these techniques, there remains ambiguity in performing mini-frac analysis. Part of the problem is that the recommended plots do not rigorously identify the various flow regimes that occur during a mini-frac fall-off. Mini-frac analysis requires a general theory that accounts for all of the actual observed flow regimes. A systematic approach based on pressure transient analysis (PTA) concepts has been developed to identify the various flow regimes (Carter leak-off being only one of them). The starting point is the Bourdet log-log derivative plot, accompanied by the primary pressure derivative (PPD) function. It will be shown that the PPD on its own has independent flow regime identification capabilities. Once specific flow regimes have been identified, specialized log-log plots can be constructed for further flow regime verification. New combination plots are then developed for each flow regime to further assist in closure pressure determination. The theory will first be developed and illustrated with various example problems.
Combined Uncertainty and History Matching Study of a Deepwater Turbidite Reservoir
Authors: Aggarwal Akshay , Du Song , King Michael J. 
Published: October 2012

Abstract
A textbook description of history matching could indicate that it is a process wherein changes are made to an initial geologic model of a reservoir, so that the predicted reservoir performance matches with the known production history. A practitioner recognizes that this is an overly simplistic description:
Does not recognize subsurface uncertainty and how we may explore this uncertainty with multiple geologic models. Offers no guidance on the requirements of spatial resolution, and how this choice may vary depending the stage of field life or reservoir processes, e.g., a pressure history match versus the modeling of a secondary or tertiary process. Offers no guidance on the nature of the geologic model: its characteristics, its level of detail, or its structure. Provides no description of the history matching process itself, nor the choices available to a practitioner.
We have been supplied with the historical field data for a deepwater turbidite reservoir, which is still under active development. We have used this reservoir to explore a number of history matching strategies. This project involved an integrated seismic to simulation study, wherein we interpreted the seismic data, assembled the geological information, performed petrophysical log evaluation and well test pressure transient analysis before creating the 3D geologic model.
In the matching process we examined the trade-off between exploring a wide number of models versus calibrating a single model. We examined the scale at which the geologic model was constructed, and how the scale of simulation could be determined. Finally, we studied both the large discrete steps in the process, and the smaller local "assisted" parameter calibration. The results provide general guidance on workflow sequence, guidance on model selection, and guidance on the scales of static and dynamic modeling. We expect many of these conclusions to have general utility, not restricted to this specific study.
The Value of Assessing Uncertainty
Authors: McVay Duane A. , Dossary Mubarak N. 
Published: October 2012

Abstract
Despite the perception of lucrative earnings in the oil industry, various authors have noted that industry performance is routinely below expectations. For example, Brashear et al. (2001) noted that average return was around 7% in the 1990s, despite using typical project hurdle rates of at least 15%. The underperformance is generally attributed to poor project evaluation and selection due to chronic bias. While a number of authors have investigated cognitive biases in oil and gas project evaluation, there have been few quantitative studies of the impact of biases on economic performance. We believe that incomplete investigation and possible underestimation of the impact of biases in project evaluation and selection are at least partially responsible for persistence of these biases.
The objectives of our work were to determine quantitatively the value of assessing uncertainty or, alternatively, the cost of underestimating uncertainty. In this paper we present a new framework for assessing the monetary impact of overconfidence bias and directional bias (i.e., optimism or pessimism) on portfolio performance. For moderate amounts of overconfidence and optimism, expected disappointment was 30-35% of estimated NPV for the industry portfolios and optimization cases we analyzed. Greater degrees of overconfidence and optimism resulted in expected disappointments approaching 100% of estimated NPV. Comparison of modeling results with industry performance in the 1990s indicates that these greater degrees of overconfidence and optimism have been experienced in the industry.
The value of reliably quantifying uncertainty is reducing or eliminating expected disappointment (having realized NPV substantially less than estimated NPV) and expected decision error (selecting the wrong projects). Expected disappointment and decision error can be reduced by focusing primarily on elimination of overconfidence; other biases are taken care of in the process. Elimination of expected disappointment will improve industry performance overall to the extent that superior projects are available and better quantification of uncertainty allows identification of these superior projects.
Examining the Effect of Cemented Natural Fractures on Hydraulic Fracture Propagation in Hydrostone Block Experiments
Authors: Bahorich B. , Olson J. E. , Holder J. 
Published: October 2012

Abstract
Micro seismic data and coring studies suggest that hydraulic fractures interact heavily with natural fractures creating complex fracture networks in naturally fractured reservoirs such as the Barnett shale, the Eagle Ford shale, and the Marcellus shale. However, since direct observations of subsurface hydraulic fracture geometries are incomplete or nonexistent, we look to properly scaled experimental research and computer modeling based on realistic assumptions to help us understand fracture intersection geometries. Most experimental analysis of this problem has focused on natural fractures with frictional interfaces. However, core observations from the Barnett and other shale plays suggest that natural fractures are largely cemented. To examine hydraulic fracture interactions with cemented natural fractures, we performed 9 hydraulic fracturing experiments in gypsum cement blocks that contained embedded planar glass, sandstone, and plaster discontinuities which acted as proxies for cemented natural fractures.
There were three main fracture intersection geometries observed in our experimental program. 1) A hydraulic fracture is diverted into a different propagation path(s) by a natural fracture. 2) A taller hydraulic fracture bypasses a shorter natural fracture by propagating around it via height growth while also separating the weakly bonded interface between the natural fracture and the host rock. 3) A hydraulic fracture bypasses a natural fracture and also diverts down it to form separate fractures. The three main factors that seemed to have the strongest influence on fracture intersection geometry were the angle of intersection, the ratio of hydraulic fracture height to natural fracture height, and the differential stress.
Simply put, the most significant finding of this research is that fracture intersection geometries are complex. Our results show that bypass, separation of weakly bonded interfaces, diversion, and mixed mode propagation are likely in hydraulic fracture intersections with cemented natural fractures. The impact of this finding is that we need fully 3D computer models capable of accounting for bypass and mixed mode I-III fracture propagation in order to realistically simulate subsurface hydraulic fracture geometries.
Reliable Completion Systems for Gas Migration Prevention
Authors: Pleasants Charles W. , Joseph Basil J. , Farrar Amy L. 
Published: October 2012

Abstract
Long String completion systems will be presented for prevention of gas migration composed of an annular casing packer with remote-set technology activated by a cementing wiper plug (CWP) with a magnetic array or an acoustic wave generator. Proven and reliable zero-extrusion gap element technology provides a gas-tight annular seal while reliability is enhanced by eliminating all communication ports and potential leak paths between the packer inner diameter (ID) and casing annulus.
There are three main benefits of these systems. They provide a reliable mechanical barrier to "flow after cementing" which can result in a significant financial impact to the operators and their service providers. They reduce / eliminate issues with annular casing pressure (ACP) and sustained casing pressure (SCP). They also provide a permanent seal between casing strings, reducing the risks of costly plug and abandonment (P&A) operations.
During cementing operations the packer is activated by the CWP. Downhole sensors detect the magnetic field generated by the CWP and initiate the setting sequence of the packing element. Another system employs an acoustic wave generator at the rig floor to initiate the setting sequence in shallow-depth applications. An optional contingency setting sequence can be programmed prior to deployment and can be deactivated remotely if required. Design and qualification of these systems will be discussed along with available field installation data. Three systems are currently awaiting field trials.
Industry standards are focused on reducing annular flow prior to, during, and after completion of primary cement jobs. While these changes will improve annular isolation, conventional cementing contains fundamental limitations that complicate control of shallow gas hazards and water flows. The US Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) has thus identified "flow after cementing" and SCP as potential hazards. The above completion systems will help alleviate these concerns. It is noted as of October-1-2012, BOEMRE has been replaced by the Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety and Environmental Enforcement (BSEE).
Impact of Matrix Block Size on Oil Recovery Response Using Surfactants in Fractured Carbonates
Authors: Goudarzi Ali , Delshad Mojdeh , Mohanty Kishore K. , Sepehrnoori Kamy 
Published: October 2012

Abstract
Oil recovery from fractured carbonate reservoirs by water flooding is often inefficient due to the commonly oil-wet nature of these rocks and the lack of sufficient spontaneous capillary imbibition driving force to push oil out from the matrix to the fracture network. Chemical processes such as surfactant/alkali-induced wettability alteration and interfacial tension (IFT) reduction have shown great potential to reduce the residual oil saturation in matrix blocks, leading to significant incremental oil recovery (IOR). However, the IOR response time is the most crucial decision factor in field projects. The magnitude and time efficiency of recovery depend on the degree of wettability alteration and IFT reduction, the nature and density of fracture network, and the dimensions of matrix blocks.
Oil recovery experiments were performed for the same matrix rock and chemical formulation, but for different sized cores to gain a better understanding of the time dependence of the recovery process. The measured oil recoveries were history-matched. The simulation models were then used to predict the recovery response times for larger cores. The controlled and systematic laboratory measurements for several core sizes helped in developing dimensionless scaling groups to aid in understanding the time dependence and upscaling of laboratory results to field-scale applications.
This finding is significant as it illustrates the extent of wettability alteration and IFT reduction needed in fractured reservoirs. Laboratory measurements and simulation work substantiate the validity and the range of applicability of upscaled procedures, and indicate the importance of viscous and buoyancy forces in larger field cases. The results of this work will be useful for the design of future field projects.
Experience with Fiberglass GRE Lined Carbon Steel Tubular for Corrosion Protection for Oil Production Applications
Authors: Sharif Qamar J. , Esmail Omar J. , Radhakrishnan Gokulnath , Simpson John A. , Bremner Martin R. 
Published: October 2012

Abstract
Saudi Aramco experienced serious corrosion problems in oil production tubing in one offshore field, attributed to presence of H2S, CO2 and varying levels of water cut.
In early 2002, the company installed on trial test basis Glass Reinforced Epoxy (GRE) or commonly known as fiberglass lined carbon steel tubing in three wells. The fiberglass lining was installed to provide a corrosion barrier to protect the steel tubing from internal corrosion. As far the technology, the fiberglass lining or sleeve is carried out joint by joint by inserting a solid fiberglass tube into the low cost carbon steel tubing and cement is pumped into the narrow annulus between the fiberglass liner and the carbon steel tubing. The connection area is protected by the combination of end flares and a corrosion barrier ring.
The company examined various methods to evaluate the performance of the fiberglass lined tubing, without having to pull out the tubing from the well as these wells are oil producers. After review of the evaluation options, it was decided to run a multi finger caliper to evaluate the condition of the fiberglass lining and check for any internal corrosion in the steel tubing. The log showed the fiberglass lining to be in good condition with no damage indicating that the steel tubing was protected from corrosion. The other two wells had no tubing leaks indicating the GRE lining is providing corrosion protection.
Based on successful trial test results, the company adopted the technology to protect tubing strings deployed in corrosive environments in oil producers, water injectors and water supply wells.
Field experience has shown that the use of fiberglass lined tubing is a low "life cycle cost" solution compared to other options. There has been no workover in these wells since installation. Today fiberglass lined tubing is applied in Saudi Aramco in high water cut oil producers, water injectors and combined water source and injection wells.
The paper shares the history of corrosion, challenges and lessons learned during the implementation of the solution, various performance assessment methods evaluated and the results and interpretation of the caliper log.
Wanted Dead or Live: Crude Cocktail Viscosity: A Pseudo-Component Method to Predict the Viscosity of Dead Oils, Live Oils, and Mixtures
Authors: Yarranton Harvey W. , van Dorp Johan J. , Verlaan Marco L. , Lastovka Vaclav 
Published: October 2012

Abstract
A broadly applicable methodology is presented to reliably predict crude oil liquid viscosity from only a gas chromatographic assay composition (C30+ is recommended). The viscosity model employs a Walther-type correlation of double log viscosity with log temperature to predict the viscosity of dead and live crude oils and mixtures. The model has three parameters: the slope and intercept of the Walther plot and a viscosibility factor to account for pressure effects. Simple mass based mixing rules are applied on these three parameters to obtain mixture viscosity. The three parameters were correlated to component molecular weight and therefore a gas chromatographic assay is the only required input apart from the temperature and pressure.
The methodology was developed from a Western Canadian dataset of two bitumens, one heavy oil, and one condensate, and then tested on an independent dataset of 10 conventional and heavy crude oils from the Gulf of Mexico, the Middle East, Asia, and Europe. The model provides un-tuned viscosity predictions within a factor of two of the measured values for dead and live crude oils ranging in viscosity from 0.5 to 500,000 mPa.s. A single multiplier is used to tune the model. Models tuned to dead oil data predict live oil viscosities and mixtures of oils with solvents to within 30% of the measured values. Models tuned to the viscosity at the saturation pressure predict the effect of temperature and pressure to within 20% of the measured values.
The method retains its accuracy when components are lumped into a few pseudo-components and is ideally suited for use in simulators for accurate liquid phase viscosity predictions over a wide range of compositions, pressures, and temperatures. It would be necessary to include the proposed mixing rules in numerical simulators. An additional advantage of the method is the reduction in viscosity measurements needed to construct an accurate viscosity model.
Thermal Performance Testing of a High-Temperature ESP Motor for SAGD Applications
Authors: Waldner Leon , Wonitoy Kelvin , Klaczek Wayne , Noonan Shauna 
Published: October 2012

Abstract
During 2012, BakerHughes, ConocoPhillips and Nexen Inc. continued their research partnership [Waldner 2011] with a new experimental test program focused on the thermal performance of Electric Submersible Pump (ESP) systems for Steam Assisted Gravity Drainage (SAGD) applications, which was completed in the high-temperature flow loop at C-FER Technologies.
Accurately monitoring the internal temperature of the ESP motor is a key consideration when trying to increase the operational longevity of an ESP system for any application; however, as the SAGD process develops, understanding this temperature profile has become more critical. This test program included several tests at various fluid temperatures and ESP operating conditions that helped determine the thermal performance of the ESP motor. Another unique aspect of this test program was the incorporation of two different temperature monitoring methods at approximately the same position on the internal and external base of the ESP motor: one internal probe positioned near the motor windings via a fiber optic sensor and one external skin temperature RTD positioned on the motor surface to monitor this important temperature differential.
This paper presents the equipment and instrumentation used, and demonstrates some of the more interesting test results, thus providing further insight into the thermal performance of this ESP motor under representative SAGD conditions between 220°C (428°F) and 250°C (482°F).