bluuebunny/crossref_metadata_2025_split huggingface dataset:
Top-Down Intelligent Reservoir Modeling (TDIRM)
Authors: Gomez Y. , Khazaeni Y. , Mohaghegh S. D. , Gaskari R. 
Published: October 2009

Abstract
This paper examines the validity of a recently introduced reservoir simulation and modeling technique. The technique, that is named Top-Down Intelligent Reservoir Modeling, TDIRM (not to be confused with BP's TDRM history matching technique), integrates traditional reservoir engineering analysis with Artificial Intelligence & Data Mining (AI&DM) technology in order to arrive at a full field model and to predict reservoir performance in order to recommend field development strategies. The distinguishing feature of this technology is its data requirement for its analysis. Although it can incorporate almost any type and amount of data that is available in the modeling process, it only requires field production rate and some well log data (porosity, thickness and initial water saturation) in order to start the analysis and provide a full field model. Presence and incorporation of other types of data can increase the accuracy and validity of the developed model.
In this work three different reservoir models with varying criteria have been generated using a commercial simulator. The models are built to investigate TDIRM's capabilities in predicting different aspects of an oil reservoir. The models include different reservoir saturation conditions (saturated or under-saturated), different number of wells and different distributions of reservoir characteristics. Production rates and well log data from the wells in the simulation model are imported into the TDIRM to develop a new empirical reservoir model and make predictions on new well performance and potential infill locations. The results from the TDIRM analysis are compared to the original simulation models. Investigation and validation of TDIRM's predictive capabilities include identification of gas cap development in the formation, identification of infill locations by mapping the remaining reserves as well as predicting flow performance of the wells that are planned to be drilled in the reservoir.
CFD Characterization of Liquid Carryover in Gas/Liquid Separator with Droplet Coalescence due to Vessel Internals
Authors: Lu Yaojun , Greene John , Agrawal Madhusuden 
Published: October 2009

Abstract
Liquid carryover in gas/liquid separators has been numerically characterized by using the Euler-Lagrange multiphase formulation together with correlations specifically developed to account for droplets coalescence due to the vessel internals. With this approach, contribution of vessel internals to flow distribution is addressed with porous medium treatment, and contribution to separation performance is considered using the local changes of equivalent mean-droplet size across each vessel internal. Numerical verifications on two vessel configurations operated at high and low pressures have shown that the vessel with proposed internals outperform the vessel with original internals, hence minimized liquid carryover rate is achieved. This CFD prediction agrees well with the existing separation theory and practical observation since only a partial perforated baffle and a vane pack are available in the original vessel. The proposed vessel however integrates the perforated baffles as flow distributor, mesh pad as droplet coalescer, and spiral flow cyclone as mist demister. Of course, combination of these vessel internals makes the proposed vessel a great upgrade to the original vessel. It is therefore demonstrated that not only CFD can be applied to characterize the overall flow distribution, but also can be extended to quantify liquid carryover, hence the separation performance of gas/liquid separators, no matter they are operated in onshore, offshore, or subsea upstream processing industries.
Cost Effective Reservoir Characterization, Utilizing Dielectric Logging Measurements, San Joaquin Basin, California
Authors: Pilman Dany , Skinner Tom , Denton Robert , Hansen Mark , Torres David 
Published: October 2009

Abstract
The San Joaquin basin (SJB) is a large asymmetric northwest-southeast trending sedimentary basin located in central California. Several of the most prolific oil fields in the continental U.S. are located within the SJB. Typical hydrocarbon production is derived from shallow heavy oil +/− 13 °API sand reservoirs and from moderately deeper lighter oil (25 to 35 °API) and gas sands as well as fractured siliceous shale reservoirs. Most heavy oil production is steam driven, resulting in compromised and variable water resistivity (Rw) values.
The dielectric logging service is used to provide a direct measurement of water filled porosity. This porosity, in conjunction with total porosity, is used to estimate the water saturation of the flushed zone (SXO). Consequently, the primary applications of the dielectric measurements in the SJB have been to resolve SXO in heavy oil steam drives.
This paper illustrates methods of reservoir analysis, proven in the SJB, that combine the dielectric data with standard triple-combo data to evaluate these complex reservoirs. With the recent downturn in commodity prices, this method has proven to be a cost effective alternative for evaluating this type of reservoirs.
Anisotropy Effects in Microseismic Monitoring
Authors: Warpinski N. R. , Waltman C. K. , Du J. , Ma Q. 
Published: October 2009

Abstract
The accuracy of microseismic monitoring is highly dependent on the quality of the velocity structure used in the analysis of the arrival time or waveform data. Because most rocks associated with hydrocarbon reservoirs are generally anisotropic, methods must be developed to circumvent the effects of anisotropy or to determine the anisotropy parameters for appropriate inclusion. Some field measurements of horizontal vs. vertical velocities are given to help assess the degree of transverse anisotropy. Synthetic case studies are also provided to show how various monitoring strategies and velocity models can affect the accuracy of the microseismic locations.
A Risk-Adjusted Method for Determining OCS Lease Abandonment Liability in the Gulf of Mexico for MMS Supplemental Bonding
Authors: Kaiser Mark J. , Kruse Bernard J. 
Published: October 2009

Abstract
In the mid-1980s, large oil and gas companies began to divest their portfolio of properties in the Gulf of Mexico. As smaller companies built up their production assets, concern was raised that the U.S. government was exposed to financial risk if abandonment responsibilities were not met. To ensure that the government is adequately protected from incurring costs associated with offshore lease abandonment, the Minerals Management Service required operators to post a supplemental bond if at least one record title holder (owner) of the lease did not satisfy a minimum threshold financial capacity. A supplemental bonding formula was developed in the early 1990s based upon the estimated cost to decommission offshore infrastructure. The purpose of this paper is to update the bonding formula and present risk-adjusted alternatives to represent the uncertainty inherent in the implementation of any formula mechanism. The philosophy of making rational tradeoffs between cost and risks is common throughout the offshore industry, and this paper describes the selection of bonding levels that balance the need of the government to minimize its decommissioning exposure at an acceptable level of risk.
Improved Oil Recovery from Combining Well Stimulation with Novel Surfactant Technologies
Authors: Berry Sandra L. , Smith Kern , Cutler Jennifer L. , Kalfayan Leonard 
Published: October 2009

Abstract
Oil and natural gas will continue to be the primary sources of energy for the foreseeable future. However, with respect to oil, field recovery rates are low (35 percent or less) and access to proven reserves is diminishing. New and better chemical technologies to maximize oil recovery are called for – especially for enhancing response from conventional well treatments in mature fields.
Enhancing oil recovery rate even fractionally can pay enormous dividends. Sandrea and Sandrea1, reported that a one percent increase in global recovery efficiency could yield an additional 88 billion barrels of oil – a volume sufficient to replace about three years of current worldwide production. Thus, very modest improvements in well performance on a global basis could substantially elevate production and unlock vast amounts of oil reserves from reservoirs already in exploitation. Beneficial consequences would be reduced dependence on new drilling and reliance on new discoveries. Clearly, within this context, technologies that can be readily and economically applied to improve oil recovery from existing wells are very attractive.
This paper introduces a novel concept in which certain surfactants with enhanced oil recovery (EOR) properties can be combined with traditional stimulation fluids; that is, production well treatments are used to deliver EOR surfactant chemistry to the formation. This concept would enable extraction of additional oil through a spontaneous imbibition process. Combined stimulation / EOR applications include propped fracturing, acid fracturing, matrix stimulation, and scale inhibitor squeeze treatments.
The paper presents laboratory data demonstrating the efficacy of two new surfactant chemistries designed to enhance both stimulation and oil recovery in naturally fractured carbonate and diatomite reservoirs. Specifically, data will be provided to show the highly synergistic effect of combining a particular EOR surfactant with carbonate acidizing.
Finally the paper discusses the applications and deployment of this EOR surfactant-aided, production enhancement concept.
Deconvolution of Wireline Formation Test Data
Authors: Wu Jianghui , Georgi Dan , Ozkan Erdal 
Published: October 2009

Abstract
Robust methods of deconvolution have been available to the well testing industry recently. This paper investigates the viability of applying a deconvolution algorithm to mini-DST data. A mini-DST test is conducted with a wireline formation tester (WFT) equipped with straddle packers. The use of straddle packers enables an isolated interval from where production can be induced. A mini-DST is actually a small-scale well test with limited entry. The production rate history of a mini-DST has special features. Because the rate of mini-DST is measured close to the source at a downhole location, it is more accurate than measurement from a well test. However, the rate history consists of hundreds of short-term build-ups due to pump characteristics. Special procedures are adopted to address these rate characteristics.
Both synthetic and field tests demonstrate that a deconvolution algorithm can be applied to mini-DST data. The application of deconvolution can enhance the radius of investigation. Because deconvolution yields non-unique results, a robust inversion requires at least two build-ups. The data sets selected for deconvolution should be consistent; otherwise, deconvolution will fail.
This paper presents deconvolution results of mini-DST data. A deconvolution algorithm is developed to address the characteristics of production rate during a mini-DST test. A comparison study with other deconvolution software is conducted. It proves that deconvolution algorithms work well with mini-DST data.
Evaluation of Haynesville Shale Vertical Well Completions with a Mineralogy Based Approach to Reservoir Geomechanics
Authors: LeCompte Brian , Franquet Javier A. , Jacobi David 
Published: October 2009

Abstract
This paper presents a methodology for characterizing the mineralogy and geomechanical properties of the Haynesville Shale. The results from two case study wells demonstrate how a perforating strategy based on mineralogy and geomechanical properties derived in part from mineralogy can improve hydraulic fracture stimulation performance.
A full suite of openhole logs (acoustic, NMR, density-neutron, and mineralogy) provides the means for estimating both geomechanical properties and reservoir quality. An accurate measurement of total organic carbon with minimum core calibration is obtained from new wireline pulsed-neutron logging technology. Utilizing primarily openhole logging data, a micromechanical model simulates axial and radial deformations of a core sample under triaxial stress. It provides the static rock mechanical properties and strengths at different confining conditions for every depth interval. A new input to the micromechanical model is the mineralogy characterization derived from a wireline pulsed neutron tool. The static rock mechanical properties and TOC derived from these methods provide the key to understanding the fracturing potential of a zone in the Haynesville Shale.
Two log examples show how optimized perforation placement based on these approaches can positively impact production. Tracer logs indicating vertical fracture containment and production data provide a validation of the approach. A post-mortem analysis of these well completions suggests that using the results of these models for fracture and completion design results in better production than wells completed differently in similar formations. The described approach brings together mineralogy, TOC, and mechanical rock properties for a complete evaluation of Haynesville Shale reservoirs with a view toward optimizing completion costs.
Asset Life-Cycle OPEX Modelling With Montecarlo Simulation To Reduce Uncertainties and To Improve Field Exploitation
Authors: Verre F. , Giubileo A. , Cadegiani C. 
Published: October 2009

Abstract
Be cost effective at early stages of field development and during mature production it is one of the most critical steps for improving risk and uncertainties management and optimization of field exploitation during the asset lifecycle.
This study shows the methodology adopted by ENI E&P to evaluate the operating expenditures (OPEX) for development projects and producing assets. This methodology adopts the concept of activity based cost (ABC) and Monte Carlo simulations to improve OPEX estimates, to influence the design optimising costs, and to reduce uncertainties throughout the exploration and production (E&P) phases from evaluation phase through mature operations up to decommissioning.
The proposed workflow process and tools were successfully applied for both development projects and mature production. In particular when used during design phases it provides an improved OPEX cost estimates compared to percentage of CAPEX methods, which enables project and operations teams to better evaluate the feasibility and operability of a project. In addition a risk analysis will be carried out for the cost model in order to mitigate the risks and uncertainties associated with the different assumptions.
Effective Geochemical and Geomechanical Characterization of Shale Gas Reservoirs from the Wellbore Environment: Caney and the Woodford Shale
Authors: Jacobi D. , Breig J. , LeCompte B. , Kopal M. , Hursan G. , Mendez F. , Bliven S. , Longo J. 
Published: October 2009

Abstract
The successful recovery of hydrocarbons from gas shales requires a fundamental understanding of the reservoir's rock-matrix properties. Information about the variable lithologies, mineralogies, and kerogen content is vital to locate favorable intervals for gas production. Knowledge of the in-situ stresses and porosity of these intervals is essential for developing hydraulic fracturing strategies to recover the gas in place. Often these properties are established from the analysis of cores extracted from the wellbore, a time-consuming practice which causes costly delays in well completions and prolonged rig time.
We demonstrate that these reservoir rock properties can be measured and predicted in-situ from the wellbore environment by a formation evaluation method that employs a combination of measurements made by downhole geochemical, acoustic, and nuclear magnetic resonance sondes. Using this combination of tool measurements we determine lithology, mineralogy, and kerogen content. The mineralogy, porosity, acoustic velocities, bulk density, pore pressure, and overburden stress are then used to compute the unconfined compressive strength, Poisson's ratio, and horizontal stress for each interval. These results can then be used to develop hydraulic fracture strategies.
The effectiveness of this approach is shown through characterization of the rock properties of the Caney and the Woodford Shale from three different wells. The ability to quantify the kerogen content from these formations is emphasized as there is currently no other direct quantification of carbon from openhole wireline logging available. This approach for characterization of shale gas reservoirs is also further supported through comparisons of core data that display the mineralogy, chemistry, kerogen content, and geomechanical properties from the wellbore section.
The Direct Measurement of Carbon in Wells Containing Oil and Natural Gas Using a Pulsed Neutron Mineralogy Tool
Authors: Pemper Richard , Han Xiaogang , Mendez Freddy , Jacobi David , LeCompte Brian , Bratovich Matt , Feuerbacher Gary , Bruner Mike , Bliven Steve 
Published: October 2009

AbstractThe assessment of reservoir productivity and subsurface hydrocarbon can be significantly enhanced through an understanding of formation mineralogy and organic carbon. Such information allows petrophysicists to resolve ambiguities in their predictions of reservoir hydrocarbon potential. While core samples are a prime source for exact formation mineralogy, excellent results can also be derived in a timely and cost-efficient manner from in-situ log chemistry measurements of the rock. A direct measurement of the formation's elemental concentrations is achieved using a gamma ray scintillation sensor in combination with a 14-MeV pulsed-neutron generator. The most important element measured is carbon, as it may provide a direct indication of reservoir hydrocarbons.This paper presents a method for determining the amount of organic carbon in subsurface formations using a pulsed-neutron mineralogy tool and a natural gamma ray spectroscopy tool. The natural, inelastic, and capture gamma ray energy spectra from these instruments are used to extract the chemistry of the subsurface formation being investigated. The elemental concentrations measured include Al, C, Ca, Fe, Gd, K, Mg, S, Si, Th, Ti, and U. Carbon is very difficult to measure without the inelastic spectrum generated from a pulsed-neutron source. An interpretation process, based upon the geochemistry of petroleum-bearing formations, is employed to derive the lithology and mineralogy which leads to the interpretation of the carbon measurement.The oil saturation can be computed in conventional reservoirs, assuming that the amount of carbon in excess of that required for the inorganic matrix mineralogy is part of the pore fluid as hydrocarbon. The direct carbon measurement is also important in laminated shaly sands or in low-salinity reservoirs, where oil saturation determination from indirect measurements, such as resistivity, is not compatible with the environment. In other formations the carbon can be determined to be a component of the rock matrix as kerogen or coal, both of which are uniquely identified with this logging system. Kerogen becomes extremely important in the evaluation of shale gas formations. Field examples are presented to illustrate the effectiveness of the carbon measurement.
Minimizing Environmental Footprint by Utilizing Prevention Technology
Authors: Clark Melanie 
Published: October 2009

Abstract
The oil and gas industry of today requires a social license to operate. As positive public perception diminishes, it demands that the industry adapt to a higher standard of operation to reduce its environmental footprint. There are systems that make it easy to achieve this and are able to fit on any rig, anywhere in the world.
Drilling fluid losses total on average more than 5000 gallons per single well. Industry adaptation in Canada is 98% in directing the discharge of fluid during connections. Surprisingly, only 12% of Canadian drilling rigs have systems in place to capture and recycle directed fluid, even though drilling operators can drastically reduce mud costs and remediation expenses by capturing, and recycling fluid before it hits the ground.
Common perception is that environmental stewardship and greenhouse gas reduction involves a prohibitive price tag, a misconception this paper will dispel. This paper illustrates the adverse effects of non-containment, introduces proactive technology available and presents several case studies demonstrating benefits of zero spill systems from a financial and environmental perspective.
Widespread implementation of zero spill technology is crucial in elevating environmental stewardship, regaining a strong social license and improving profitability during capricious times in the market.
Low-Rheology RDF Successfully Drills Troublesome Qannik ERD Wells in the Alpine Field, North Slope, Alaska
Authors: Alvord Chip , Noel Brian , Galiunas Elizabeth , Murphy John , Cucullu Jim , Ornt Christian 
Published: October 2009

Abstract
A proactive approach was undertaken to successfully drill and complete wells at the beginning of the Qannik development drilling program in the Alpine field on the North Slope of Alaska. Due to economics and logistics of the remote Alpine field, the well design req-uired drilling relatively small diameter, long horizontal intervals in the shallow Qannik formation at 4,000-ft true vertical depth (TVD). This paper describes the comprehensive approach, extensive testing and field implementation that led to a successful drilling program using a low-rheology reservoir drill-in fluid (RDF).
The goal was to successfully drill within a narrow hydraulic window bounded by the Equivalent Static Density (ESD) for wellbore stability and Equivalent Circulating Density (ECD) to stay below the fracture gradient. The first test well, drilled with a conventional mineral-oil-based drilling fluid or "mud" (MOBM), experienced massive lost circulation due to wide fluctuations between ESD and ECD while drilling the 6,000-ft (1,830-m) horizontal production section. This necessitated another approach to economically drill the 9,000-ft (2,740-m) horizontal production intervals planned for the development wells.
A low-rheology mineral-oil-based RDF utilizing a dry micronized weighting material was selected to help eliminate sag potential, allow the ECDs to stay below the fracture gradient, maintain wellbore stability, minimize fluid losses and minimize formation damage. Actual field data showed an approximate 1.0 lb/gal decrease in ECD over the conventional fluid. The final results of the drilling program were all eight wells being successfully drilled. The first well's lateral planned section for 9,000 ft (2,740 m) was cut short by 3,000 ft (910 m) due to severe lost circulation but adjustments to fluid weight and properties, drilling practices and careful geo-steering delivered the seven other wells as planned. The deepest well reached over 18,000 ft (5,490 m) in measured depth (MD) with over 8,400 ft (2,560 m) of horizontal lateral. One of the main drivers in the success of the Qannik drilling program was the use of micronized weighting material in the specially designed low-rheology MOBM.