bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Multi-Jet Gun Improves Well Production in the North Sea
Authors: Scott Martin S. , Carvajal Gustavo A. , Manning Doug , Hendry Nicholas , Rogers Mike 
Published: February 2011

Abstract
The main focus of any perforation system is to establish effective hydraulic communication between the wellbore and the reservoir. A primary attribute for this connection is maximum penetration in the undamaged reservoir rock, especially in mature and highly depleted reservoirs. Drilling and completion fluids cause a certain amount of damage in the near well bore region, the perforating tunnels must bypass the damaged region to create the effective flow path and enable maximum well productivity. The challenge is to create a deep, clean, undamaged tunnel to maximize oil and gas production from the reservoir.
A new Triple-Jet™ perforating system was recently introduced in the North Sea, and it uses the existing shaped charges and a slightly-modified hollow steel carrier as from those currently used in the industry. This system provides a new perforating concept that exploits the beneficial aspects of firing a bank of three co-linear focused charges into the formation. The jets from the upper and lower perforating charges are angled to intersect within the formation, while the jet from the center charge is slightly delayed such that its perforating tunnel has the benefit of penetrating the tensile-stress-altered rock within the formation. The resulting shock wave from the converging jets produces a proportionally smaller crushed zone and weakened material around the perforation tunnel that is easily removed by low underbalance methods. Simulated downhole testing conditions show that this system significantly improves both penetration and flow performance and provides potentially greater well productivity than the same charges loaded in a traditional hollow steel carrier with similar charge-to- charge phasing angle. Because the Triple-Jet system produces weakened rock that is easily removed by low underbalance, it is ideal for both new well completions and re-perforating existing wells.
The new perforating technology complies with similar safety standards as conventional perforating systems, raises no additional issues with explosives licensing, guns are run and fired in the conventional manner, and does not require substantial new work or training for the crew or platform management. This paper compiles a series of laboratory experiments that are modeled with an analytical simulator and provides a brief description of the job-field application.
Comparison of Power Law and Modified Hyperbolic Decline Methods
Authors: Seshadri J. , Mattar L. 
Published: February 2011

Abstract
The Power Law decline analysis method has been offered as a way for predicting gas reserves in low permeability reservoirs, by matching early transient data but not over-predicting reserves as can happen when using hyperbolic decline and a high b-exponent.
This paper compares the goodness-of-fit and reserve prediction results of the Power Law versus the Modified Hyperbolic decline method; the Modified Hyperbolic being a hyperbolic decline with an imposed limit on how low the decline can become, thereby also avoiding reserve over-prediction.
Linear flow is a common occurrence in tight gas wells. For this situation, the modified hyperbolic decline (which has a direct theoretical connection) is better suited than the power law decline. Furthermore, for low values of n, Power Law appears to degenerate into hyperbolic decline.
Using synthetic and real production data, is it demonstrated that, for the most part, data matched using Power Law can also be matched using Modified Hyperbolic decline. Modified Hyperbolic decline is well understood and accepted by the industry; on the other hand, the Power Law is complex and its constituent variables are not intuitive.
Integrated Dynamic Reservoir Modeling for Multilayered Tight Gas Sand Development
Authors: Diomampo G. P. , Roach H. , Chapin M. , Ugueto G. A. , Brandon N. , Fleming C. H. 
Published: February 2011

Abstract
This paper summarizes the approach used for applying integrated reservoir modeling to the tight gas sands of the Pinedale Anticline in western Wyoming. The simulation of tight gas sands such as those at Pinedale has always been challenging because of the high degree of heterogeneity that needs to be retained to replicate reservoir performance, coupled with computing constraints. Added to this, simulating the Pinedale reservoir has its own unique challenges due to its characteristically thick gross sand interval composed of multiple, heterogeneous sand bodies produced commingled in a well.
An intensive data-gathering program to investigate optimum well spacing accompanied the simulation effort. A significant part of this program was the installation of pressure monitor wells1 to detect communication with surrounding producers at the hydraulic fracture stage level. This was coupled with multiple time-lapse production logs. The two data sets together allowed better definition of stage performance at producing wells.
Static models were built with fine resolution to duplicate reservoir heterogeneity. However, upscaling was necessary due to computing constraints. The upscaling procedure of Li and Beckner2 was utilized to maintain substantial geologic heterogeneity. The upscaled model was calibrated to mimic fine scale well performance prior to history matching.
Several sector upscale models were history matched using a statistical approach without compromising key aspects such as reservoir connectivity and proper mass withdrawal from each geologic sub layer. Hydraulic fractures in each stage were characterized through history matching. Given the geostatistical nature, an exact match on every frac stage and every pressure gauge located away from the producer should not be expected. Rather, a more statistical definition of a history match should be adapted to a level that still gives confidence in forecasting the value of future infill wells. The history-matched parameters were then statistically distributed to forecast more realistic future development wells.
The availability of data including pressures at observation wells and production logs was critical in narrowing the range of uncertainty in the history-matched scenarios and reduced the degree of non-uniqueness in the model thus resulting in increased confidence in model forecasts. This paper describes the methods used to overcome many of the problems encountered in modeling heterogeneous tight gas sands, such as at the Pinedale Anticline.
The Development of a New Reservoir Simulator to Model Polymer Flooding and Advanced Wells for Enhanced Heavy Oil Recovery in Bohai Bay
Authors: Zhang L. , Zhang Y. , Gong B. 
Published: February 2011

Abstract
Enhanced oil recovery by polymer flooding and advanced (multi-lateral) wells has been applied to develop China's offshore heavy oil reservoirs. Current commercial simulators lack the ability of modeling polymer flooding processes and multi-segment wells simultaneously, thus limits their application in making reliable production predictions and the overall development plan.
In this work, a black-oil simulator is extended to model polymer flooding by adding brine and polymer pseudo-components to the governing equation. The polymer solution, reservoir brine and the injected water are represented as miscible components of the aqueous phase. Necessary factors have been taken into account for the construction of mathematical model, such as inaccessible pore volume, polymer shear thinning effect, polymer adsorption, and relative permeability reduction factors, etc. These polymer-induced effects, modeled as nonlinear relationships, are based on lab experiments conducted upon core and PVT samples from China's heavy oil reservoirs in Bohai Bay. A fully implicit formulation is applied to solve the governing equations.
In modeling of the multi-lateral wells which are commonly applied in Bohai Bay oil fields, the multi-segment well approach is adopted. The well index (productivity index) is calculated using a 3D projection method based on Peaceman's model. This method is extended to enable its application in both structured and unstructured grid system to fully resolve complex geometrical interaction between multi-lateral wells and the reservoir. The pressure and fluid concentration distribution along wellbores is calculated through the homogeneous model, the result of which can better describe the true physics in the wellbore.
This work, for the first time, provides the development framework to model polymer flooding and advanced wells for EOR in heavy oil fields. Comparing with numerical results from commercial simulators, this model yields better accuracy and more importantly, enables the modeling of polymer flooding processes and multi-segment wells simultaneously.
Steam and Glean: Planning to Learn in a Potential World-Class Heavy Oil Project
Authors: Bynum C. W. , Weller M. F. , McManus C. D. , Haskett W. J. 
Published: February 2011

Abstract
As the first hydrocarbon development in Madagascar, the Tsimiroro field is an onshore heavy oil asset (mean resource nearing 3.5 billion barrels @14°API) located inland from the western coast covering approximately 900 square kilometers. The project is in early assessment and resource identification phase nearing steam flood pilot implementation. Adequate interpretation and treatment of existing subsurface data is crucial to determining the optimal path to maximum field value. Beyond resource, there are substantial variables related to above-ground risk and operational decisions including processing, transportation, and marketing. While important for any project, these aspects become critical for this, the first commercial project in a non-oil producing country with minimal infrastructure.
Subsurface and operational risks, as well as strategic project objectives/decisions were approached using industry leading probabilistic methods, capable of testing pathways through highly complex situations. The evaluation included an integrated approach to deal with the full value-chain of the steam flood project. This process, rooted in statistics and decision theory, helps determine significant value drivers and illuminates uncertainty reduction opportunities. It identifies and prioritizes risk mitigation measures leading to a better expected asset value.
A pilot program was re-designed to focus on critical learnings and will help de-risk many of the important project variables at a relatively low cost - an insight which could not be gleaned from a traditional deterministic analysis. A probabilistic evaluation of the resources in place indicated that further delineation of the field via drilling and Electrical Resistance Tomography would resolve significant subsurface uncertainty. Further, investigation of export transportation methods, alternatives for oil upgrade, and commercial alternatives for oil disposition were evaluated in detail to reveal which options were viable to pursue, and which had low priority for further investigation.
Experimental Measurement of Diffusion Coefficient of CO2 in Heavy Oil Using X-Ray Computed-Assisted Tomography Under Reservoir Conditions
Authors: Song L. , Kantzas A. , Bryan J. 
Published: February 2011

Abstract
Injection of carbon dioxide has shown process and economical advantages for enhancing the heavy oil and bitumen recovery by reducing viscosity under the reservoir conditions. Mass transfer is the first mechanism to occur when carbon dioxide is injected into the reservoir. Consequently, the measurement and evaluation of the diffusion coefficient is essential to develop feasible and economic technology for extraction of heavy oil and bitumen. However, not much effort has been put into the experiments of carbon dioxide and heavy oil for understanding and calculation of the gas-liquid diffusion coefficient. The purpose of this study is to evaluate the feasibility of determining experimental diffusion coefficients of carbon dioxide in heavy oil by employing X-ray Computed Assisted Tomography (CAT) and a non-iterative finite volume method, and investigate the impact of different experimental conditions on diffusion coefficients.
The results indicated that the measured carbon dioxide diffusion coefficients are consistent with those reported in the literature for similar gas-heavy oil systems. X-ray Computed Assisted Tomography (CAT) and a non-iterative finite volume method were successfully applied to study the diffusivity of carbon dioxide in heavy oil. In addition, the concentration and diffusion coefficients of carbon dioxide in heavy oil depend on diffusion distance as well as on diffusion time and pressure.
An Analytical Model to Predict Cumulative Steam Oil Ratio (CSOR) in Thermal Recovery SAGD Process
Authors: Miura Kohei , Wang Jin 
Published: February 2011

Abstract
This paper presents a simple yet sophisticated analytical model to predict cumulative steam oil ratio (CSOR) using the material/energy balance and gravity drainage theory, in which CSOR is a function of average reservoir properties (porosity, permeability, heat capacity, and thermal conductivity), and time-dependent variables (injection temperature, rising chamber height, chamber oil saturation, and producing fluid temperature) to mimic the practical SAGD process. This model has been applied to predict CSORs of the typical wells in the JACOS’ Hangingstone SAGD project. History match results show the reliability and accuracy of the model at different geological conditions. The analytical model has proven to be satisfactory to predict CSOR by reasonably adjusting a few reservoir parameters, such as formation permeability, effective net pay, and operational parameters.
From CSG to LNG: Modeling and Understanding Key Subsurface Uncertainties for the Development of a Surat Basin Opportunity, in Queensland, Australia
Authors: Lagendijk E. , Ryan D. 
Published: February 2011

Abstract
Arrow Energy intends to develop its certified coal seam gas reserves in the Surat Basin to supply gas to a proposed liquefied natural gas (LNG) plant located in Gladstone, Queensland. The large scale development of the Surat Basin for the LNG Project required basin-wide geological modeling. The Surat Basin coal structure and properties were reviewed in detail and modeled to estimate Gas Initially in Place. Dynamic simulation was subsequently performed to estimate total recoverable volume and generate a robust development plan for the LNG Project.
Key subsurface risks consist of access to sufficient gas volumes within the area of interest and gas deliverability to meet and maintain gas supply to the LNG Project. To minimise the likelihood, and to reduce the consequences of these risks, subsurface uncertainties were identified and low and high values for each uncertainty were assessed with the aim to understand impacts on the LNG Project.
Gas content, permeability and Net to Gross resulted in the biggest impact on the LNG Project, followed by relative permeability curves, coal heterogeneity, isotherms, permeability variation with pressure, coal compressibility and potential aquifer connection. Other uncertainties, including coal depth cut-off, sorption time and initial reservoir pressure had a lower impact on the number of wells required for the LNG Project.
Subsurface sensitivity analysis combined with probabilistics was used to generate 90%, 50% and 10% probability subsurface models. These were carried forward for development planning to generate a range of development outcomes and production forecasts for economic evaluation to ensure a robust LNG field development plan.
This paper describes the integrated reservoir data analysis and dynamic modeling methodology for the purpose of the large-scale development of this Surat Basin opportunity and outlines how key uncertainties were identified and addressed.
An Innovative Cementing Solution for the Grosmont Carbonate
Authors: Arseniuk S. E. 
Published: February 2011

Abstract
Alberta's oil sands contain an estimated 286 billion m3 (1.8 trillion barrels) of bitumen, including more than 64.5 billion m3 (406 billion barrels) in the Grosmont Carbonate. The Grosmont at Saleski represents a significant resource, which will be developed from pilot to commercial development. The operating company plans to recover bitumen from the Grosmont using solvent-cyclic, steam-assisted gravity drainage (SC-SAGD), beginning with a pilot in the Saleski field.
The Grosmont has been noted for drilling challenges relating to lost circulation, including difficulty in cement placement. To address these challenges, lightweight, foamed, thermal cement was specifically engineered, tested, and qualified for use at the pilot. This blend addresses placement challenges and was designed to achieve the mechanical properties required for zonal isolation and well integrity throughout the life of the well.
This paper discusses the design and development of the blend using finite-element analysis (FEA) software to evaluate blend suitability, laboratory testing results to confirm basic properties, installation in the pilot wells, and results using ultrasonic cement-inspection tools.
Modeling Well Performance Data From Overpressured Shale Gas Reservoirs
Authors: Thompson J. M. , Nobakht M. , Anderson D. M. 
Published: February 2011

Abstract
It is widely known that shale gas wells require hydraulic fracturing to generate greater wellbore contact with the reservoir in order to achieve economic gas rates. When this type of completion is applied to ultra-tight rock, long-term linear flow is expected and has been widely confirmed through analysis of production data. However, in some shale gas production data, such as the Haynesville, we have observed a markedly different behavior, characterized by the appearance of apparent boundary dominated flow early in the production life of the well. Furthermore, we have observed major inconsistencies between drawdown and buildup data in some of these wells, which is a reliable indicator of degradation in well productivity through time. Although the nature of the productivity loss (kh, skin, fracture conductivity, etc) is usually indeterminable from well performance analysis, its magnitude is clearly evident in well production histories that contain intermittent shut-in periods with measured buildup pressures.
In overpressured reservoirs containing fractures (such as the Haynesville), the reduction of pore pressure resulting from well production through time will sometimes cause the fractures to close, thereby decreasing fracture conductivity. This process, while expected, has not been experimentally verified for the Haynesville (at least within the public literature). We believe that the concept of pressure dependent fracture conductivity (which can be modeled as effective permeability) is a suitable explanation of our observations of well performance data in the Haynesville.
In this paper, we use simulated data to illustrate that the presence of pressure dependent permeability causes a clearly identifiable signature in production history data containing intermittent buildups. In addition, we will show that in the absence of buildup data, analysis of well performance will significantly under-predict original-gas-in-place (OGIP) and expected-ultimate-recovery (EUR) in reservoirs with pressure dependent permeability. Finally, we will show that operating conditions (changing or constant flowing pressure) may have a huge impact on the interpretation of production data, particularly (but not exclusively) in the presence of pressure dependent permeability.
A Study of High-Quality Foamed Fracturing Fluid Properties
Authors: Wheeler Richard S. 
Published: February 2011

Abstract
In recent years successful stimulation and extraction of hydrocarbons from unconventional reservoirs has led to various approaches to the stimulation process. Slickwater stimulations pumped at very high flow rates have become the staple in formations such as the Barnett Shale. High treatment rates are made possible by the implementation of low dosages of polyacrylamide, which lower the effective pipe friction. This type of treatment process is common among other shale and tight gas plays throughout North America. Other types of treatments include conventional crosslinked or linear gelled fluids. Some treatments combine the conventional crosslinked fluids and the slickwater approach. Experimentation with multiple stimulation programs is a response to the changes in formation properties that vary from one formation to the next and within areas of the same formation. Over the last few years there have been several successful treatments implementing a high-quality foam stimulation in some shale formations. These treatments have usually included a gas phase in excess of 90 quality and often as high as 99 quality. This type of treatment is especially fitting for low-pressure reservoirs and in depleted zones. One advantage of a high-quality foam is its reduced environmental impact by using very small quantities of water as compared to high-rate slickwater stimulations. In these particular high-quality foams, a viscoelastic surfactant gel is used in the liquid phase as the gelling and foaming agent. With the combination of high-quality foam and non-damaging viscoelastic gel, the total fluid is completely non-damaging to the formation. Successful treatments in formations in the northeastern United States have led to a demand for use in other formations, necessitating a better understanding of fluid properties in order to design treatments. Very little published data is available for high-quality foam fluid properties. A study has been conducted to examine the fluid characteristics of high-quality foams as compared to typical 50 - 70 quality foams. This study will show trends of viscosity, foam stability and temperature sensitivity of high-quality foams using xanthan, guar-based gelling agents and viscoelastic base fluids.