bluuebunny/crossref_metadata_2025_split huggingface dataset:
Is there a "Silver Bullet Technique" For Stimulating California's Monterey Shale?
Authors: Shaari Nabil E. , Minner W. A. , LaFollette R. F. 
Published: May 2011

Abstract
A large number of California's Central Valley, coastal, and offshore oilfields produce from the Miocene Monterey shale formation. Example oilfields with productive Monterey intervals include offshore and inland fields such as Hondo, Point Arguello, Lost Hills, Elk Hills, Belridge, and North Shafter/Rose. Example productive formation members that produce from the Monterey shale would include the Antelope Shale, McLure shale, McDonald Shale, and the Reef Ridge. The Monterey shale is both a reservoir and hydrocarbon source rock. There are large variations in reservoir properties and general interval behavior due to differences in the lithology, diagenetic state, mechanical properties, and the stress state. Generally the Monterey shale has a low matrix permeability of 0.01–1.0 md, but effective permeability can be higher due to natural fracture conductivity. Porosity spans a huge range – from as low at 10% to as high as 70%.
One illustrative example is in Southeast Lost Hills, where vertical wells are drilled and hydraulically fractured to target thick Opal-CT and the deeper cherty/quartz-phase Monterey pay intervals. The design and placement of multiple fracture treatment stages with appropriate conductivity and half-length is a requirement for a successful field development. In contrast, offshore Monterey developments have usually targeted intersecting the conductive natural fracture network in quartz-phase intervals. For this flavor of the Monterey, an acid job can effectively stimulate production by removing the drilling/completion damage and dissolving the calcite filling in natural fractures.
A significant thickness of Monterey siliceous shale is present across a large area in California. The oil industry has learned much from unconventional shale reservoir development elsewhere in the country. Is it possible that Monterey siliceous shale will be transformed into the California version of an ‘unconventional’ shale resource? The key will be to identify the Monterey intervals with the most potential, and apply the proper development drilling and completion strategy, with changes made to accommodate the low-mobility multiphase liquid flow. General Monterey development challenges include: a) defining the structure, b) identifying the target pay intervals within the thick depositional intervals, c) understanding the lithology and the reservoir / rock properties of the different pay zones, d) understanding and designing the optimum stimulation treatment(s) and e) determining the optimum well development pattern and completion strategy to incorporate all the above requirements. Is there a "silver bullet" strategy that will enable success in the pervasive Monterey siliceous shale? The purpose of this paper is to stimulate industry thought and discussion.
Comparing the Results of a Full-Scale Buckling Test Program to Actual Well Data: New Semi-Emprical Buckling Model and Methods of Reducing Buckling Effects
Authors: Mitchell Sarah , Moore Norman Bruce , Franks James , Liu Gefei , Yang Yanghua 
Published: May 2011

Abstract
Buckling and its effects are topics of economic and technical interest as ERD and horizontal wells become critical to maximizing recoverable reserves, particularly in the Continental United States and Alaska. Previous work has resulted in important discoveries about drill string buckling, but to date, little testing has been done on actual drill pipe in a controlled manner, particularly in measuring drill string whirl. As a result, there can be disparities between theoretical predictions of buckling effects versus actual field results. These disparities can result in unrealistically high friction factors required to bring calculated values close to actual data, or in many cases, operational difficulties such as high torque, low ROP, drill string failures, inability to maintain directional control, or reach the planned depth can result.
To learn more about drill string behavior in buckling conditions, a full-scale buckling test fixture was developed to evaluate the effects of buckling on 2 ⅞−, 3 ½−, and 4-inch drill pipe while sliding and rotating inside 7 inch casing. The test fixture incorporated a variety of sensors and cameras to characterize torque, drag, vibration, and drill string deformation under buckling loads. As part of the test program, low friction non-rotating protectors were also tested to measure performance under buckling conditions.
The test results show that drill string buckling occurs at far lower loads than predicted by current models, possibly caused by minor deformations inherent in real drill pipe. The results also show that for a given amount of torque or drag, protectors increased the available compressive load by 20 to 30% and substantially reduced vibration caused by drill string whirl.
The test results were used to develop a new Semi-Empirical Buckling Model that predicts contact forces resulting from drill string buckling and also the torque and drag effects of drill string whirl. This model was then incorporated into torque and drag modeling software where it was compared against actual data from a large number and variety of wells. The results show an ability to more accurately predict torque, drag, and vibration caused by buckling and whirl.
New Experimental Model Design for Systematic Investigation of Capillarity and Drainage Height Roles in Vapor Extraction Process
Authors: Ahmadloo F. , Asghari K. , Henni A. , Freitag N. P. 
Published: May 2011

Abstract
Vapor Extraction is a solvent-leaching gravity drainage-based process that can be used for improving recovery factors from0020low-pressure heavy oil and bitumen reservoirs. Despite numerous experimental and numerical studies having been conducted, the associated production mechanisms in this process are still poorly understood. This paper presents the details of a new experimental approach that can overcome limitations of previous physical models for representative simulation of capillarity and drainage height effects on performance of the vapor extraction process. Unlike other studies in literature, the physical models in this study were designed to provide a constant composition solvent surface at one face of the heavy oil saturated sandpack. To eliminate the effect of pressure surges, a new effluent collection system was successfully designed and tested. This experimental setup made it possible to study the interplay between the selected parameters on stabilized drainage rates under effects of capillary and gravity forces. Here, a comprehensive experimental study was conducted in two 2D visual physical models using Plover Lake oil from west-central Saskatchewan and n-butane as solvent in the permeability range of 5.1–6.5D. This paper discusses the significant effects of capillarity and drainage height on the stabilized drainage rates, Vapex dimensionless number, and efficiency of mass transfer phenomena in the Vapex process. This study provides in-depth knowledge necessary for developing more reliable mass transfer models to depict the vapor extraction process in the presence of capillary forces.
Numerical Optimization of Clearwater Formation's Response to SAGD under New Well Configurations
Authors: Tavallali M. , Maini B. , Harding T. 
Published: May 2011

Abstract
The Cold-Lake oil sands contain the second largest reserves volumes among the oil sands deposits in Canada. The bitumen and heavy oil are contained in various sands of the Lower Cretaceous Mannville Group – Clearwater Formation.
For the past 30 years, Cyclic Steam Stimulation (CSS) has been the commercial thermal recovery method employed in the Cold Lake area. More recently, Steam-Assisted Gravity Drainage (SAGD) has been field tested in number of pilot projects at Cold Lake. Although SAGD has been demonstrated to be technically successful and economically viable, questions remain regarding SAGD performance compared to CSS. A more comprehensive understanding of the parameters affecting SAGD performance in the Cold Lake area is required. Well configuration is one of the major factors which require greater consideration for process optimization.
This paper presents a numerical simulation investigation of the impact of using several modified well configurations for SAGD in the Clearwater Formation in Cold Lake area in order to improve the process performance. The technical feasibility of applying each arrangement was evaluated through sensitivity analysis using a fully implicit reservoir thermal simulator (CMG STARS 2009.13). In order to account for frictional pressure drop and heat losses along the wellbore, the fully coupled wellbore/reservoir (discretized wellbore) model was utilized during the course of this study. The reservoir and fluid properties were selected to represent the main bitumen production area at Cold Lake.
The new well configurations provide operational and economical enhancement to the SAGD process over the standard well configuration (a horizontal injector lying approximately 5 meters above a horizontal producer) in Cold Lake area. The SAGD process response to different reservoir parameters of the Cold Lake Formation, such as initial injectivity, mobile water saturation, and reservoir heterogeneity has been investigated for the most promising of the new well configurations.
Upscaling for Field-Scale In-Situ Combustion Simulation
Authors: Zhu Z. , Bazargan M. , Lapene A. , Gerritsen M. , Castanier L. , Kovscek A. 
Published: May 2011

Abstract
In traditional thermal reactive reservoir simulation, mass and energy balance equations are solved numerically on discretized reservoir grid blocks. The reaction terms are calculated through Arrhenius kinetics using cell-averaged properties, such as averaged temperature and reactant concentrations. The chemical reaction front is physically very narrow, typically a few inches thick. To capture accurately this front, centimeter-sized grids are required that are orders of magnitude smaller than the affordable grid block sizes for full field reservoir models. We propose a new method based on a non-Arrhenius kinetic upscaling approach. We do not resolve the combustion front on the grid, but instead use a subgrid-scale model that captures the overall effects of the combustion reactions on flow and transport, i.e. the amount of heat released, the amount of oil burned and the reaction products generated. The subgrid-scale model is calibrated using fine-scale highly accurate numerical simulation and laboratory experiments. This approach significantly improves the computational speed of in-situ combustion simulation as compared to traditional methods. We are currently developing a field-scale simulator using the above ideas. Test cases illustrate the solution consistency when scaling up the grid sizes in multidimensional heterogeneous problems. The methodology is also applicable to other subsurface reactive flow modeling problems with fast chemical reactions and sharp fronts.
A Three-Parameter Dual Porosity Model for Naturally Fractured Reservoirs
Authors: Jabbari Hadi , Zeng Zhengwen 
Published: May 2011

Abstract
This study presents a new model to analyze the behavior of naturally fractured reservoirs (NFRs). The model considers the geomechanical behavior of the fractured reservoirs and the corresponding effects on the fracture aperture, which may be an important parameter for stress-sensitive NFRs. It includes the elasticity parameters, such as Poisson's ratio and Young's modulus.
Pressure depletion in an NFR, inherent to production, can result in effective stress change that, in turn, may change fracture permeability in NFRs. This may influence the behavior of NFRs, which has been studied thoroughly in the literature; however, not analytically but only numerically. A rigorous mathematical model is developed in this study which couples geomechanical and fluid flow aspects for characterizing a stress-sensitive NFR. In the model, we consider a semi-infinite radial flow with flux boundary conditions at the wellbore (Neumann condition) and constant pressure at infinity (Dirichlet condition). It is also assumed that the external forces acting to the reservoir are constant, that there is interaction between the two regions, i.e. matrix and fracture system, via the change of pore pressure and effective stress.
Since the change in effective stress induced by reservoir compaction may affect the pressure buildup curves in NFRs, new equations on buildup interpretation are developed to better understand this effect, and to precisely evaluate the reservoir properties. An iterative algorithm is also developed which enables us not only to interpret the buildup data to compute the fracture parameters, namely fracture porosity, fracture permeability, fracture storage capacity, and the elasticity parameter, but also to evaluate them more accurately. Such a new technique improves NFR characterization through the inclusion of the fourth dimension, time, into buildup interpretation. This new well test interpretation method is a dynamic reservoir characterization, which is usually the mission of time-lapse (4-D) multicomponent seismology.
From this study, we found that knowing three parameters is sufficient to both distinguish a reservoir with dual porosity from that of a homogenous one and to characterize a dual porosity reservoir. Two of the parameters represent the fracture storage capacity and matrix-fracture interaction. A third one reflects the effect of both matrix geomechanics and fracture aperture decline on the behavior of NFRs as time progresses. These parameters can be obtained by precisely interpreting drawdown or buildup tests. This solution is applicable to any reservoir containing dual porosity rocks.
World's Deepest Thru-Tubing Electric Submersible Pumps
Authors: Julian J. Y. , Patterson J. C. , Yingst B. E. , Dinkins W. R. 
Published: May 2011

Abstract
This paper describes the development, history, and successful deployment of the world's two deepest Thru-Tubing Conveyed electric submersible pumps (TTCESP's). These are the first TTCESP's deployed inside of 7" casing. ESP's are a form of artificial lift which consists of a pump, motor, and electric cable, typically deployed by a rig and connected to electric power at surface. Their advantage is that they create greater drawdown than other forms of artificial lift, thus achieving higher production rates. However, conventional ESP's require expensive workover rigs to replace pumps, the component that fails most frequently. ConocoPhillips Alaska, Inc. (CPAI) developed TTCESP technology to replace failed pumps raidly and economically. In this system, a rig conventionally deploys the electric cable, motor, and seal sections, with a special latching device for the pump. The pump is pulled and replaced with slickline (wireline) or coiled tubing, eliminating the requirement of a rig.
The original TTC systems were developed for 7-5/8" cased wells. Over the past ~10 years it was common belief that they could not be deployed at the Milne Point Field in Alaska due to the limitations of its smaller 7" 26# cased wells. This paper discusses the enabling technologies that were developed to allow running TTCESP's in 7" casing, including a wellhead spoolpiece and low clearance ESP clamps.
West Sak TTCESP run time data indicates the time between rig workovers will increase from 3.5 to 6 years. Pumps can be replaced for 5–10% of rig costs without the safety and environmental impacts associated with rigs. Additionally, production losses while waiting for a rig are eliminated because slickline and coiled-tubing units are readily available on the North Slope of Alaska. TTC pumps can easily be upsized or downsized to optimize pump flow rate due to changes in production rates. This technology is of interest in areas where rig costs are high, including arctic, remote, and offshore locations. It is also beneficial where rig availability is low.
Outer Concentric String Casing Damage Evaluation: Advancements in Electromagnetic Inspection Data Interpretation for Common North Slope Well Completions
Authors: Burton Joey , Yang Hongying 
Published: May 2011

Abstract
Alaska's North Slope wells are subject to a variety of mechanisms that cause corrosive damage to outer casing strings. These include: (1) near-surface casing damage resulting from the ingress of oxygenated (surface) water; (2) corrosive power fluids pumped down the inner annulus of venturi pump wells; and (3) exposure to formation salt water in intervals of poor cement quality. The importance of maintaining casing integrity for safety and environmental reasons, combined with the high cost of pulling tubing strings on the North Slope create a need for an economical means of evaluating outer casing string integrity with the tubing in place.
The successful use of AC magnetic wave, electromagnetic pipe inspection technology to qualitatively assess outer concentric string casing damage for certain well completions has been well documented for applications on Alaska's North Slope since 2006. Information and conclusions drawn in existing literature are all based on the comparison of tool recordings made in the field to the visual inspection of casings subsequently dug up or removed from the well. While these comparisons illustrate many good correlations between recorded metal loss indications and areas of severe metal loss observed in some completions, there remains a need to better quantify the minimum threshold for the extent of casing damage that can be detected via this method.
This paper presents the results of surface tests conducted on dual concentric string pipe configurations with an array of engineered metal loss features designed to test the tool's response to total volumetric metal loss and the spatial configuration of damage to the outer string. The tool's response to deep pitting on the external surface of the inner concentric string is tested as well. Conclusions are drawn in respect to the approximate size and shape of defects that can be expected to be detected for the concentric pipe configurations tested. The application of this knowledge to data recorded in the field will add greatly to the confidence of risk assessments made with this technology in well work decision processes.
Ranking the Resource Potential of the Woodford Shale in New Mexico
Authors: Bammidi V. S. , Balch R. S. , Engler T. W. 
Published: May 2011

Abstract
The Upper Devonian Woodford Shale ranges from a thickness of 0 ft to 300 ft and is found at depths of 7,000 ft to 18,000 ft in the Delaware Basin. The Woodford is thermally mature over its entire extent in New Mexico: In the deeper parts of the Delaware Basin, it is in the thermogenic gas and condensate window; on the Northwest Shelf and where present on the Central Basin Platform, it is in the oil window (Broadhead 2010). Southeastern New Mexico is subdivided into Regions I, II and III based on the intensity of the fracture networks, thermal maturity and Total Organic Carbon (TOC) (Comer 2005).
Miller's (2010) gas shales ranking scorecard used parameters like total organic carbon, vitrinite reflectance, shale thickness, gas-filled porosity, clay content, quartz content, fluid compatibility, natural fracture intensity, tectonic stress and reservoir pressure gradient. The range of the scale of ranking is 0 to 100 points and for reference, the Barnett has 73 points. The better the total points, the better are the prospects of finding shale gas. Each of the regions (Regions I, II and III) were ranked for the prospects of shale gas using Miller's (2010) ranking scorecard and assigned a score of 68, 66 and 48 respectively. The results showed that Region I and II have better chances of finding shale gas. Finally an assessment was made to quantify the volumes of oil and gas in-place using Comer's (2005) Hydrogen mass balance method. The estimated volumes were 36 billion barrels of original oil in-place and 44.5 trillion cubic feet of original gas in-place in comparison to 119 billion barrels of original oil in-place and 230 trillion cubic feet of gas in-place in the Woodford for the entire Permian Basin (Texas & New Mexico). The assessment confirms that Woodford shale is a major unconventional source of both oil & gas in New Mexico.
Analyzing Wellbore Temperature Distributions Using Nonisothermal Multiphase Flow Simulation
Authors: Wang Zhe , Horne Roland N. 
Published: May 2011

Abstract
The need to interpret wellbore temperature profiles measured by Distributed Temperature Sensors (DTS) requires a correspondingly sophisticated type of well model. To be specific, this well model should be capable of predicting pressure and temperature distributions under a nonisothermal, multicomponent and multiphase production scenario. This paper describes the procedure of building a numerical well model, in which wellbore pressure and temperature were solved separately and then coupled by iteration. Accuracy was assured by the following three ways: 1. Using drift flux model to predict multiphase flow pressure; 2. Fluid PVT properties were obtained by solving Equations of State, which is more accurate than the values obtained by averaging or mixing rules; 3. Using numerical methods to solve the heat transfer between wellbore and formation, avoiding the assumption of an invariant relaxation length. This model was verified by comparing with several other models. Finally, based on this well model, several phenomena (e.g. multiphase flow, Joule-Thomson effect) affecting the pressure and temperature distribution were studied and their influences were evaluated. This study concluded that a rigorous and complete well model is important for accurate prediction of the temperature profile under complicated flow scenarios. This work allows flowrate profiling based on DTS data. The understanding of how different phenomena influence the temperature distribution is helpful to understand downhole production scenarios.