bluuebunny/crossref_metadata_2025_split huggingface dataset:
Alternative Interpretations of Shale Gas/Oil Rate Behavior Using a Triple Porosity Model
Authors: Tivayanonda Vartit , Apiwathanasorn Sippakorn , Ehlig-Economides Christine , Wattenbarger Robert A. 
Published: October 2012

Abstract
In this work, the fully transient triple porosity model proposed by Al-Ahmadi and Wattenbarger (2011) is selected to model the existence of natural fractures in shale reservoirs. This triple porosity describes three linear flow systems: from the matrix into natural fractures, from natural fractures into hydraulic fractures, and from hydraulic fractures into the wellbore. To completely identify this mathematical model, properties and dimensions of three mediums (matrix, natural fractures, and hydraulic fractures) must be known. This may be too complicated to be a practical interpretation tool.
To use the triple porosity model in a practical way, the original model is simplified. Assuming an infinite conductivity of hydraulic fractures, the triple porosity model is reduced to a dual porosity model. This Simplified Model considers only the natural fracture and matrix systems and treats the hydraulic fractures as a constant pressure boundary. The analysis equations and guidelines for this Simplified Model are presented for interpreting production data.
Interpretation guidelines are proposed corresponding to five production scenarios which are combinations of bilinear flow, linear flow, and boundary dominated flow (BDF) periods. With the interpretation guidelines, various analysis equations for different flow periods or different physical conditions are used to interpret production data. Field examples are presented with the calculation procedures of interpretation guidelines. The possible errors in general interpretation are also presented. Furthermore, this work also compares the results from the Simplified Model with those from a model with no natural fracture.
Produced Water Treating Systems -Comparison between North Sea and Deepwater Gulf of Mexico
Authors: Walsh J. M. , Georgie W. J. 
Published: October 2012

Abstract
It has often been noted that water treating systems in the North Sea differ from those in the deepwater Gulf of Mexico (GoM). The objective of this paper is to provide an understanding of the reasons for these differences.
In terms of platform technologies, and extraction strategies, there are fundamental differences between the two regions. FPSOs (Floating Production Storage Offloading) and fixed leg platforms are commonly used in the North Sea, whereas in the deepwater Gulf of Mexico there are currently no FPSOs, and only one fixed leg platform (Bullwinkle). Floating Spars and Tension Leg Platforms are typically used in the deepwater Gulf of Mexico. Thus, there is much greater deck space and weight availability for North Sea platforms than in the deepwater Gulf of Mexico. In addition, almost all North Sea fields are developed using pressure maintenance which relies on water and/or gas injection. Hence the water production in many of these fields has reached high water cut. In the Gulf of Mexico, there is only a handful of fields with water injection and most production is relatively dry.
The approach in this paper is to compare the systems to Best Practices in water treating system design and to consider the reasons for deviation from the Best Practices. Factors which account for this deviation include capital and operating costs, extraction techniques, reservoir characteristics, the properties of the fluids being treated, the target specifications, and the obvious differences in platform type (fixed structure in shallow water versus floating structure in deep water). In addition, modeling tools are used to answer "what if’ questions. This provides a detailed understanding of the relative importance of various factors which differentiate the systems in the two regions (such as inlet fluid shear and temperature, separator flux rate, residence time, application of hydrocyclones, etc).
While the overall conclusions of the analyses can be readily anticipated (i.e. deepwater systems are designed to minimize weight and space), the detailed understanding provided here gives insight into the design of water treating systems in general. It emphasizes the importance of carrying out effective water treating early in the process (i.e. in primary separation as done in the North Sea), and the necessity of using large end-of-pipe equipment when this is not possible (as in the deepwater, due to high cost of weight and space).
Position/Fracture Uncertainty and Ranging During Drilling and Fracturing
Authors: Samuel Robello , Germain Olivier , Gang Rui 
Published: October 2012

Abstract
Unconventional shale drilling has developed rapidly during the last decade. The development of substantial prospectsespecially in shale gas playsrequires advanced technologies and prudent well monitoring. Many new operational challenges are associated because of simultaneous operationssuch as drilling and fracturing nearby wells.
While drillingthe interaction of the fractures from nearby wells results in pressure communication and unexpected well kicks. Because of the low porosity of those tight reservoirsthose uncommon well kicks have so far not been severebut taking the time to control wellbore pressures adversely affects the efficiency of the drilling process and increases the nonproductive time. Additionallyas fracturing becomes more efficientand conductivity increasespossible future events might have much more dramatic consequences. This paper presents a method that uses the positional uncertainty of the well being drilledpositional uncertainty of the fractured/fracturing wellsand uncertainty of the fracture length and fracture orientation to avoid this problem. The paper discusses the reasons and challengestechniquesand lessons learned to solve the simultaneous moving boundary conditions between the reference wells and multiple offset wells. The method of explicit solution avoids a trial-and-error procedure and provides excellent maneuverability of planning requirements. The modified model and methods provided the use of exact mathematical solutions and uncertainty ellipses estimates.
This method can also be used to monitor the influence of other variablessuch as temperature cyclingoil drainage distancewellbore storage effectand reservoir pressure transients. The method presented can be used in the planning stage to ensure optimal well placement; it can also be used for designing super fractures between wells. The study indicates that the use of real-time data from drilling and fracturing wells can predict the need for remedial action.
Experimental investigation of Pressure Drop/Flow Rate Relationship for Small Aperture Holes for High Viscosity Fluids
Authors: Jain Rachna , Long Ted A. , Dickson Jasper , Brown Scott V. , Shtepani Edmond 
Published: October 2012

Abstract
This paper studies the effect of viscosity and fines particle loading on the pressure drop across a 4mm orifice in a specific geometry built to mimic a representative well completion. In previous studies, most of these orifices have been validated experimentally for viscosities up to 200cp only for such completions. The current study focused on a wider viscosity variation (1cp – 3000cp) with lower flow rates (0.1m3/day - 30m3/day). The pressure drop was measured across the orifice and through the entire pipe assembly. The measured data was non-dimensionalized using the Euler number and plotted against the Reynolds number for all the rates and viscosities. The orifice pressure drop data overall agreed well with the limited data that was available from the literature. It was also compared and validated against commercially available CFD software. The effect of sand particle loading was also studied and its effect on apparent viscosity increase was measured in the laboratory. The pressure drop-flow rate relationship disclosed in this paper can be used to design effective completions for intermediate/high viscosity oil applications and will be able to predict the completions pressure drop more accurately.
Thermal Management of Electronics Used in Downhole Tools
Authors: Verma Sandeep , Elias Quincy 
Published: October 2012

Abstract
In the search for new oil and gas reservoirs, the industry is likely to drill, characterize, complete, and produce wells with a reservoir temperature higher than 150°C, which are considered to be high-pressure/high-temperature (HP/HT) wells. An increasing number of ultra-HP/HT (high-pressure, high-temperature) wells with reservoir temperature above 205°C are also likely to be drilled. Downhole tools experience high failure rates at these conditions since there is a limited catalog of conventional electronic components that can reliably operate above 150°C Active and passive cooling of electronics are options for extending the operability and reliability of downhole tools in HP/HT and ultra-HP/HT environments.
Passive methods provide cooling for a short duration because they are designed to provide a fixed capacity for heat absorption from the tool. Examples of such methods include the use of a flask (or vacuum-jacketed tool housing) and the use of phase-changing materials. If the tool is likely to be exposed to HP/HT or ultra-HP/HT conditions for a long duration, then the use of active cooling methods may become necessary. Active cooling methods use electric power to reject heat (absorbed from the tool) at relatively lower temperatures to the higher-temperature wellbore fluid (or the formation) by using a suitable heat pump or a thermodynamic cycle. It is important to choose the optimal thermodynamic cycle and working fluid so that the power consumption is minimized. We present a process analysis of various thermodynamic cycles and demonstrate that the vapor compression cycle is the most efficient thermodynamic cycle for cooling downhole tools. In addition, we present an analytical methodology to identify a suitable fluid for this cycle. Water was chosen as the fluid for the vapor compression cycle; it is environmentally friendly, easily available, and has a high latent heat of vaporization.
The vapor compression cycle was demonstrated in a part of a wireline formation tester tool. A special chassis was constructed that permitted flow of refrigerant through it. Heating elements and thermocouples were installed on the chassis to simulate heat dissipation from electronic components during operation. To simulate the high-temperature downhole environment, the tool was heated by two 4.5feet long, 2500 W jacket heaters. Steam was supplied to this chassis at different flow rates to balance the heat load at two reservoir temperatures. Heat generated on the chassis, and heat transferred across the vacuum-jacketed housing was absorbed by the refrigerant. This demonstrated that the vapor compression cycle is efficient and capable of actively cooling downhole tools.
Experimental results indicate that, using the vapor compression cycle with a refrigerant flow rate of 10 mL/min, it is possible to remove 175 W and 100 W of heat from the chassis when the tool is exposed to a reservoir temperature of 200°C and 250°C, respectively.
A Novel Technique for Wells that Require Gravel Packing for Sand Control and Inflow Control Devices for Managing Water Encroachment: Case Histories from Ocelote Field in Colombia
Authors: Velez Beatriz , Charry William , Duarte Anker , Beltran Alexander , Prent Larry , Rubiano John , Trujillo Hernando , Tengono Jose Aldemar , Castano Ricardo , Ortiz Everardo , Florez Darwin , Guerrero Ximena , Navarro Claudia , Stamm Bryan , Lopez Nicolas 
Published: October 2012

Abstract
Gravel packing is one of the commonly used sand control techniques in long openhole horizontal completions. Although numerous wells have been gravel packed with either one of the two placement techniques (α/β or shunt tubes), achieving a complete pack with sand control screens that have inflow control devices (ICD) can be challenging to say the least. This is because of the high pressure drops needed for the fluid to flow through the ICD into the base-pipe/wash-pipe annulus at the typical rates used for gravel packing, resulting in significant pressure rise and exceeding the fracturing pressure of the formation. Although using a screen without an ICD at the bottommost joint would certainly allow the α-wave to reach the toe, the pressure buildup will occur as soon as the β-wave proceeds upstream of that joint, which will either result in formation fracturing and bridging or significant rate reduction and α-wave height increase (near the heel first), both events resulting in a premature screenout.
Ocelote field in Colombia requires sand control, and gravel packing and standalone screens (SAS) have both been used in openhole horizontal completions in various parts of the field. An additional challenge in this field has been the premature water breakthrough from the aquifer leading to very high water cuts after only a few months of production. ICDs have successfully been implemented in SAS completions to address this challenge in other parts of the world. Similarly, gravel packing has been successful in controlling sand in parts of the field where SAS was considered unsatisfactory, although water cut in most of these wells increased to 70 to 90% after only 3 months of production.
In this paper, we present a novel technique for wells that require gravel packing for sand control and ICD functionality for managing water encroachment. Detailed in the paper is the first application of the proposed technique in Ocelote field, which resulted in 100% pack efficiencies using the water packing technique as well as significant reduction in water cuts, with substantial improvement in the project economics.
Added Value by Fast and Robust Conditioning of Structural Surfaces to Horizontal Wells for Real-World Reservoir Models
Authors: Stenerud Vegard R. , Kallekleiv Hans , Abrahamsen Petter , Dahle Pål , Skorstad Arne , Viken May Hege 
Published: October 2012

Abstract
Structural updates for a complex reservoir model require time-consuming manual work, therefore, updates are rarely performed. This leads to an outdated model that gradually loses its predictability. Eventually, this results in model breakdown, and a new model must be built from scratch. Continuously updatable reservoir models avoid this and increase the value of models as a tool in decision making. In addition, easily updateable structural surfaces enable several structural realizations for spanning the uncertainty.
We present the use of a method for fast and robust updates of structural surfaces in reservoir models. We will focus on updates using zone data from horizontal wells (zone-log conditioning), since this traditionally has been a bottleneck that needs tedious manual work prone to error. In zone-log conditioning, we try to generate horizon surfaces that honor the geological zonation along the well paths. This is important for property modeling, and is crucial for fluid-flow simulations. Our method is robust, fully automated, and is built on a consistent mathematical framework that includes specified input-data uncertainties. It has provided satisfactory results for large real-world reservoir models where standard methods and work processes have failed. The field example presented shows a reduction from 22.9 % to 0.9 % in incorrectly honoring of the zone logs by applying this method rather than the standard approach. The remaining 0.9 % is due to conflicting data, gridding errors, and is difficult to get rid of even with manual editing. We consider this a large step forward with respect to providing an up-to-date basis for decisions that also can account for structural uncertainties.
Buckling of Bouyancy Assisted Tubulars
Authors: Arslan Mehmet , Ozbayoglu Evren M. , Miska Stefan Z. , Yu Mengjiao , Takach Nicholas , Mitchell Robert F. 
Published: October 2012

Abstract
Use of buoyancy has emerged to provide multiple solutions to overcome the drag problem for wells with shallow and high step-out profiles. Although both full and partial floatation methodologies have been employed successfully to extend the reach in many field cases, the influence of buoyancy on tubular instability has not been investigated yet. This paper presents an extensive experimental and analytical study, focusing on static tubular instability inside horizontal wellbores with emphasis on buoyancy. In terms of the experimental research, running tubular into horizontal wellbores was simulated with four different pipes, varying buoyancy and loading speed. Throughout the tests, axial loads both applied to the pipe and transmitted through the pipe were recorded simultaneously, with respect to pipe displacement. Experiments reveal that currently existing models give reasonable approximations as long as buoyancy is not included into the tests. The major interpretation from experiments is such that contrary to what currently existing expressions imply, i.e. tubular buckles immediately as effective weight approaches zero; even for naturally buoyant conditions, considerable amount of axial load is still required for both buckling initiation and helix formation. As buoyancy increases further, results and predictions diverge from each other considerably. In order to eliminate the discrepancies between results and predictions, theoretical study was conducted. Empirical correlations that also consider the influence of buoyancy on critical buckling loads are presented. Finally, another pipe was also tested within different buoyancy conditions to validate the equations developed. Experimental results of this pipe closely match the new analytical findings. This experimental and analytical study provides useful results for future applications with buoyancy assisted tubulars, in terms of practical engineering and design calculations.
Fracability Index – More Than Just Calculating Rock Properties
Authors: Mullen Mike , Enderlin Milt 
Published: October 2012

Abstract
The geometry and complexity of hydraulic fracture stimulation treatments is largely controlled by the heterogeneous and anisotropic nature of rocks. Conventional practice in designing fracture stimulation treatments revolve around the parameters that can be changed and considers the rock being stimulated as homogenous and isotropic. Engineers can influence the frac geometry to some degree by changing the pumping rate, fluid viscosity and proppant loading. If the goal of a frac job is to get the fluid and proppant below the ground, most any formation can be frac’d. The degree to which a reservoir will generate complex fracture networks, break into fresh rock or create a simple bi-wing fracture can be influenced by the stimulation treatment job design. The creation of a complex fracture network is a function of the stimulation fluid rheology, rock properties and presence and orientation of preexisting planes of weakness acting in the stress state of the reservoir.
The index of brittleness or fracability is a term frequently used to describe formations that are likely to create complex fracture networks when fracture stimulated. In a broader view, fracability is much more than just calculating mechanical rock properties. A new definition of fracability, the Complex Fracability Index (CFI), proposed here integrates the sedimentary fabric, stratigraphic properties, mineral distribution and the presence and orientation of preexisting planes of weakness operating in the present day stress state into a single metric. This approach establishes a means to qualitatively or quantitatively determine the degree to which the rock will have the ability to create a complex fracture network or just a simple planer hydraulic fracture using the mechanical rock properties and the dip and orientation of the preexisting planes of weakness in the rock in the modern day stress state. The CFI methodology is not limited to shale reservoirs. Examples from the Barnett Shale and the tight sand in the Piceance Basin will be discussed.
A Fully-Coupled Free and Adsorptive Phase Transport Model for Shale Gas Reservoirs Including Non-Darcy Flow Effects
Authors: Xiong X. , Devegowda D. , Michel G. G. , Sigal R. F. , Civan F. 
Published: October 2012

Abstract
Accurate modeling of gas through shale-gas reservoirs characterized by nano-meter pores where the effects of various non- Darcy flow regimes and the adsorbed-layer are important is presented and demonstrated by several examples. Quantification of gas transport may be accomplished using the transport equation that is valid for all flow regimes. This equation though needs further modification when transport is through a media where the gas is adsorbed onto the pore wall. In the presence of adsorption, there is a pore pressure dependent loss of porosity and cross-sectional area to free gas transport. The apparent gas permeability correction is accomplished for various flow regimes using the Knudsen number by consideration of the reduction of the cross-sectional area to free gas transport in the presence of adsorption. We show that transport in the adsorbed layer may contribute significantly in the total gas transport in these nanopores. An effective transport model is presented to account for the impact of adsorption through two mechanisms. First, we modify the transport equation to account for the pore-pressure dependent-reduction in the volume available to free gas transport; second, we model transport through the adsorbed layer using Fick's law of diffusion. The coupled model is then compare to conventional transport models over a wide range of reservoir properties and conditions.
As pore-pressure is reduced, adsorbed phase gas desorbs into free gas and apparent permeability increases. The difference in the estimated apparent permeability with and without the consideration of the adsorption volume can be a factor of two or more at initial reservoir conditions. Diffusion on the surface of organic pores can be a substantial transport mechanism in shales depending on the pore connectivity, pore pressure, and pore size distribution in the organic pores. The interpretation of production data will be compromised without considering the effects of adsorption on apparent permeability. This work implies that permeability measurements for shale gas reservoirs must be done with methane at in-situ pore pressures. Because these corrections are pore-pressure not effective pressure dependent, effective pressure is not a valid parameter to use in quantifying the pressure dependence of these transport equations.