bluuebunny/crossref_metadata_2025 huggingface dataset:
Designing a Successful Training Class: Benefits and Challenges of Knowledge Transfer from Chemists to Engineers
Authors: Vorderbruggen M. , Woo G.
Published: October 2009

We are currently entering a crisis point in the petroleum industry. The cost and complexity of acquiring hydrocarbons is increasing while the pool of experienced personnel shrinks. It generally takes years of real world experience to create an expert field engineer capable of handling all the factors involved in getting the goods out of the ground. Mentoring and specific on-the-job training/classes helps bring new engineers up to speed, but often these lessons are limited to how and when to do something, especially in the area of chemical products. Understanding the mechanics of their chemical tools empowers engineers.

Lacking both general experience and knowledge about their chemical tools, field engineers require more support both from their supervisors and from their tech support laboratory. These technology support requests translate into time lost, money spent, and customer dissatisfaction. Laboratories are being overrun by requests that would not have been asked a few years ago. To combat this more actual chemistry is being taught to both our new and older engineers. The goal is to replace experience with knowledge, to give them a deeper understanding of what their chemicals are doing to the formation, to the equipment, and to each other. By understanding the why, they can figure out the how and the when.

The benefits of such training are presented in this paper. These include such things as increased confidence, quicker problem solving, improved customer trust, and more. Suggestions on how to teach chemistry to engineers are included. Presentations, homework and tests must be worded in "Engineerese" rather than "Chemical Mumbo-Jumbo" to maximize transfer of knowledge. The end result of all this is improved response times, improved customer relations, reductions in technology support requests, and assorted other benefits. In other words, it makes the company more money.
Simulations of Field Development Planning Help Improve Economics of Heavy-Oil Project
Authors: Teotico Dwight , Schauerte Luke , Griffith James , Schottle Gary , Mehl Ralph
Published: October 2009

When Shell began an ultraheavy-oil development in Alberta, Canada, the field plan was based on manual pad positioning without consideration for surface hazards, trajectory constraints, or injector/producer slot requirements arising from the prefabricated pad configuration.

Shell teams were challenged to investigate alternative field development plans to reduce the initial investment. The volume of wells, surface hazards, trajectory constraints, and pad slot configuration requirements for injector-to-producer ratios made this a formidable task. Shell leveraged the expertise of third-party consultants and powerful software to generate numerous development scenarios, which enabled the Shell staff to focus on the economics of each plan.

An aerial image that delineated surface hazards, an elevation grid, and injector/producer targets were loaded into the 3D subsurface visualization environment of the software to generate pad placement simulations, including trajectory designs. The software followed the Shell planning constraints and avoided all surface hazards.

The analyses were conducted for the highest, lowest, and median number of pads. From these three scenarios, a value analysis was plotted. This value analysis enabled the planning team to identify the optimal surface-to-reservoir configuration and to maximize the value of the field by delivering all of the reservoir targets, while minimizing the number of pads needed to drill. The output also yielded field cumulative values, including total and nominal well length, to support future economic analyses.

The analysis determined that 87 pads maximized the value of the field when 42-well pads were considered. Additional studies determined that when 50-well pads were considered, more than 99% of the planned reservoir targets could be drilled from 72 major and four or fewer minor pads. In either case, a significant reduction from the original 98 pads was realized. Through the combined efforts of Shell engineers and third-party consultants, as well as the use of state-of-the art software, this optimization was completed in only eight worker-weeks.

This paper describes the software and processes used to reduce Shell's estimated field development costs and to minimize the environmental effect of the field by reducing the number of pads required.
Top-Down Intelligent Reservoir Modeling (TDIRM)
Authors: Gomez Y. , Khazaeni Y. , Mohaghegh S. D. , Gaskari R.
Published: October 2009

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

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

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

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

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

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

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

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

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

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

The 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

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

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.
Optimizing Directional Drilling While Minimizing the Risk of Well Collision in Offshore Drilling
Authors: Sharma Nitin , McDonald Mike , Mohammed Jeffrey , Daire Bryan , Eicks Theodore , Jew Leo
Published: October 2009

As offshore drilling grows more crowded and more complex, greater emphasis is placed on avoiding collisions with offset wellbores. The implications of a collision with an existing well are very real, and care must be taken to minimize the risks associated with such incidents. Collision with a producing well carries additional risks, including potential well-control situations and lost income from shut-in wells. With more wells being drilled from multi-well locations, well collision is becoming a very real possibility. Today's drilling trends toward more directional, horizontal, and fishbone multilateral wells, often with several from a single slot using subsea wellheads. This paper covers the practices for sidetracking out of the well using a whipstock and minimizing the risk of collision with offset wells. Special emphasis is placed on optimizing whipstock placement (orientation and depth), use of gyroscopic tools while milling and drilling ahead, and the use of traveling cylinders for collision avoidance. Case histories are presented here to illustrate the successful application of these techniques.
Photo Review: Remote Assessment of HSE Conditions at Operational Facilities Using Digital Photography and On-Line Meeting Capabilities
Authors: Simon Flavio , Godfrey Richard , Pilling Lee , Graf Jake
Published: October 2009

Operating hundreds of facilities globally, both fixed and temporary, larger petroleum industry companies are challenged to ensure consistent compliance to HSE standards. Although local and regional staff members conduct regular inspections, corporate HSE inspections are less frequent due to the challenges of distance and limited resources. The Photo Review process was developed to bridge this gap.

Briefly, corporate HSE staff selects a facility for a Photo Review based on a number of criteria, such as leading and lagging indicators, follow-ups or elapsed time since prior inspections. Then, regional or local HSE staff members walk-about the facility, capturing digital photos according to a pre-defined shot-list that specifies points-of-interest to the corporate HSE team. The photos are inserted into a preformatted presentation template and posted to the Company's inspection database.

In an online video-teleconference, local management then conducts a virtual tour of their facility with the HSE team providing commentary, coaching, and solutions as needed. Depending on the perceived level of commitment and compliance to standards, the outcome is either "all good", "needs attention", or a follow-up in-person corporate inspection is warranted.
Understanding Reservoir Mechanisms Using Phase and Component Streamline Tracing and Visualization
Authors: Kumar Sarwesh , Datta-Gupta Akhil , Jimenez Eduardo A.
Published: October 2009

Streamline simulation has received considerable attention because of its computational efficiency and also for being visually appealing and physically intuitive. Conventionally streamlines are traced using total fluid fluxes across the grid cell faces. The visualization of total flux streamlines shows the movement of tracer and water flood front, injector-producer relationship, swept volumes for injectors and drainage volumes for producers. However, total fluxes mask many important features of reservoir flow embedded in the individual phase fluxes. These include reservoir dynamics, such as phase distribution, appearance and disappearance of phases, local drive mechanisms and reservoir miscibility conditions for CO2 or solvent flooding.

In this paper we demonstrate the benefits of visualizing phase and component streamlines, which are traced using phase and component fluxes respectively. Both three-phase black oil and compositional simulation are used to visualize reservoir flow and to understand the drive mechanisms active in the reservoir. Although the phase and component streamlines are not suited for flow simulation because of their local discontinuities, these streamlines provide unique insight into the reservoir processes and recovery mechanisms. In this study, the phase and component streamline tracing is done using phase/component fluxes from commercial finite-difference black oil and compositional simulators.

We demonstrate the power and utility of the phase and component streamlines using synthetic and field examples. The phase streamlines are shown to capture the dominant flowing phases in different parts of the reservoir and to help us optimize locations of infill injectors and producers. Based on the appearance and disappearance of phase streamlines, we can identify the regions of the field where different drive mechanisms such as waterflood and solution gas drives are active. The field applications involve waterflooding in a structurally complex reservoir in South America and also, a CO2 injection project in a large carbonate reservoir in Canada. We use component streamlines to track the movement of injected CO2 in the reservoir. By tracking the phase and component streamlines, we can clearly distinguish the CO2 in the gas phase and the dissolved CO2. This not only helps optimize CO2 injection but also has important implications in the effectiveness of the CO2 sequestration.
Pore Networks and Fluid Flow in Gas Shales
Authors: Wang F. P. , Reed R. M. , John A. , Katherine G.
Published: October 2009

Favorable gas content, depth, and thickness, along with high brittleness of the Barnett Shale in the Fort Worth Basin, North Texas, have made the basin one of the best shale-gas plays in North America. Using recent pore images and geochemical data for the Barnett Shale, we investigated potential effects of organic matter on petrophysical properties, pore networks and fluid flow in gas-shale systems.

Four types of porous media are present in productive gas-shale systems: nonorganic matrix, organic matter, natural fractures, and hydraulic fractures. Organic-matter pores, ranging from 5 to 1,000 nm, are especially important because they can adsorb gases as well as store free gases. Gas content and adsorption data from Barnett Shale also suggest that a significant amount of free gas is stored in organic matter. Porosity in organic matter can be five times higher than that in the nonorganic matrix. Organic matter is oil wet, and associated pores work as nanofilters for hydrocarbon flow, suggesting that fluid flow in organic matter is predominantly single phase.

Owing to high porosity, predominantly single-phase flow, and the gas slippage effect, gas permeability in organic matter, significantly higher than that in the nonorganic matrix, tends to enhance gas permeability in gas shale. In addition, the pore network in organic matter, can be larger than that in the fractures, could be the hidden pathway to high gas production in gas shale when connected to natural and hydraulic fractures.
Investigation of Formation Connectivity Using Asphaltene Gradient Log Predictions Coupled with Downhole Fluid Analysis
Authors: Zuo Julian Y. , Mullins Oliver C. , Dong Chengli , Betancourt Soraya S. , Dubost Francois X. , O’Keefe Michael , Zhang Dan
Published: October 2009

Reservoir fluids often demonstrate complicated phase behaviors in a single column as a result of the impacts of gravity, thermal gradients, biodegradation, active charging, water washing, leaky seals, and so on. Moreover, reservoir compartmentalization can cause discontinuous distributions of fluid compositions and properties, making the proper characterization of fluids and reservoirs even more challenging yet compelling. The recognition of flow barriers or compartmentalization is key to effective and efficient reservoir characterization, production, and management. Downhole fluid analysis (DFA) is an essential tool for determination of the compositional gradients in real time at reservoir conditions. However, analysis of flow connectivity in the reservoir by DFA can be complex, especially when the reservoir fluid compositional gradients are small with depth. In this case, the analyses of bulk fluid properties may not be sufficiently sensitive. However, DFA of asphaltene gradients provides an excellent method to delineate the complexity of black oil columns. Moreover, DFA measurements are very sensitive to and often linear in the asphaltene content.

A methodology has been developed to estimate downhole fluid coloration variations with depths using an equation-of-state (EOS) approach coupled with the DFA tools. The DFA tools are used to determine downhole fluid compositions of CO2, C1, C2, C3−C5, C6+, and the coloration associated with asphaltene contents. Recent additions to DFA measurements include fluid density and viscosity. The delumping and characterization procedures proposed by Zuo et al. (2008) are applied to obtain the detailed compositions including asphaltenes and the parameters of the EOS model. Fluid profile and coloration logs are computed by "tuning" the molar mass of asphaltene nanoaggregates against the DFA coloration logs. The methodology has been successfully applied to investigate reservoir connectivity for offshore and laboratory centrifugation cases. The adjusted molar mass of asphaltene nanoaggregates is determined to be in a range of 3,000–8,000 g/mol for the cases studied, yielding molecular aggregation numbers of roughly 7 in reservoir fluids, which is in agreement with laboratory studies. The results obtained in this work demonstrate that the proposed method provides a useful tool to reduce the uncertainties related to reservoir compartmentalization and to optimize DFA during the logging run. In addition, the results indicate that treating part of the Cn+ (e.g., C36+) fraction as an asphaltene component (monomer) in the traditional cubic EOS approach is contradicted by the recent observations that asphaltenes are nanoaggregates in crude oils.
A Fully Coupled Numerical Poroelastic Model to Investigate Interaction between Induced Hydraulic Fracture and Pre-Existing Natural Fracture in a Naturally Fractured Reservoir: Potential Application in Tight Gas and Geothermal Reservoirs
Authors: Rahman M. M. , Rahman Sheik S.
Published: October 2009

This paper investigates interaction of induced and pre-existing fracture by coupling wellbore, induced fracture and natural fracture in a poroelastic reservoir. Possibilities of fracture crossing, bending, arrest and shear dilation for various angles of approach are investigated under different scenarios: in-situ stress state, reservoir rock and fluid properties and characteristics of natural fracture.

The fully coupled poroelastic model and results of this study in particular have a beneficial application in the design and optimization of hydraulic fracture treatments in naturally fractured reservoirs, therefore tight gas reservoirs and enhanced geothermal systems. The model can be extended to design stimulation of naturally fractured reservoirs based on shear dilation (high pressure low injection rate).

In this paper we have demonstrated that natural fractures, faults and other discontinuities severely restrict propagation of an induced fracture. In-situ stress state, orientation and shear strength of pre-existing fracture prove to be most significant factors that influence the fracture propagation trajectory:

– Because of the poro-elastic formulation it was possible to investigate the change in stress state ahead of the fracture tip and evaluate whether the fracture is going to be attracted or rejected by the interface. It was observed that high leak off influences dilation of natural fracture ahead of the arrival of the induced fracture tip. – Possibilities of fracture arrest increases with increase in high differential stress state and shear strength of pre existing fractures. – Fracture crossing is another dominating behaviour for natural fracture with small aperture while fracture dilating for natural fracture with larger aperture.

Fully coupled poroelastic modelling allowed us to gain new knowledge on interaction between induced and pre-existing fractures. This methodology and knowledge base will significantly improve our current approach to design and implement hydraulic fracture treatment in naturally fractured reservoirs.
Oil Recovery by Low Salinity Brine Injection: Laboratory Results on Outcrop and Reservoir Cores
Authors: Boussour S. , Cissokho M. , Cordier P. , Bertin H. , Hamon G.
Published: October 2009

Over the last 10 years, the emerging EOR process by injection of low salinity water has been investigated through numerous laboratories and some field tests. Extensive research programs have been launched by different teams, aiming at better understanding the involved mechanisms (clay release, pH increase, cation exchange). One of the main issues is to explain the observed dispersion in additional oil recoveries.

In this study, we integrate new experimental observations to the literature to carry out a mechanism analysis of recovery by low salinity injection. These new results were obtained on outcrop sandstones with 9-10 % clay content (Cissokho 2009) and on reservoir cores with reservoir oil.

Very positive results to dilute brine injection on the outcrop rock / crude oil of field A system have been observed either in tertiary mode or secondary mode. Corefloods on the same outcrop rock/ crude oil system show that the benefits of low salinity brine injection may vary against the flood temperature. Corefloods in pseudo-reservoir conditions using reservoir cores and the same crude oil of field A showed no response to injection of low salinity brine. Corefloods using reservoir cores and oils from three different fields did not show any positive response to dilute brine injection.

In this paper, we analyze the different theories proposed in the literature and present experimental counter-examples for most of them, particularly related to the presence of kaolinite, divalent ions in injected brine, or the effect of temperature. We show that low salinity water injection as an EOR method appears very sensitive to a combination of several parameters.
Development of a Ribbon Gravity Gradiometer and its Applications for Reservoir Monitoring
Authors: Neill F.
Published: October 2009

Gravity Gradiometry has been rapidly gaining acceptance as an additional tool in the geophysical tool box when deployed in either aircraft or ships. The potential for its use for downhole applications including reservoir monitoring has been identified for some time. However the sensors used for surface applications are unsuitable for downhole applications and as a result of the lack of a suitable sensor, little investigation has been carried out on wellbore applications.

This paper briefly explains gravity gradiometry and its history in the oilfield. Measurements of gravity (Gz)and gravity gradiometry (Γzx) are compared with the advantages and disadvantages of each outlined. The potential application of the technology as an ultra-deep reading density measurement for reservoir monitoring is shown. Depending on the resolution of the sensor and the reservoir parameters the paper shows that it will be possible to detect a gas / liquid interface in a directional manner at distances up to one kilometre from the wellbore.

The paper explains the principles of the ribbon gravity gradiometer and its suitability for downhole deployment. Its inherent common mode rejection and the subsequent relative immunity to downhole noise and deviation issues are outlined. The equations for the derivation of the borehole gravity gradients are shown and immunity to environmental influences explained. The limited impact of near well bore effects is explained. Depending on the deployment method, time averaging is shown to increase sensitivity and an example is shown of the depth of investigation versus sensor sensitivity for oil/water, oil/gas and gas/water interfaces.

The paper clearly demonstrates that the ribbon gravity gradiometer is a viable downhole sensor and will provide a significantly deeper depth of investigation than traditional nuclear or electrical measurements.
New Integrated Approach for Updating Pore-Pressure Predictions During Drilling
Authors: Lüthje M. , Helset H. M. , Hovland S.
Published: October 2009

This paper presents a new integrated approach for updating pore pressure predictions during drilling of a well. Pore pressures in sedimentary rocks can vary from hydrostatic (normal) pressures to very high (abnormal) overpressures. Sediment pore pressures are important constraints that need to be carefully considered when planning a new well and will influence drilling strategy, casing program, and mud-weights.

A pre-drill prediction of pore pressures is used as input in the well planning phase and is based on an assumption of the local geology in the prospect, typically extrapolated from near-by wells. However, the pre-drill prediction may be inaccurate or erroneous due to incorrect assumptions.

To help solving this problem we have developed an integrated approach for updating the pore pressure prognosis during drilling. The methods for pore pressure predictions are integrated with an eDrilling system for real-time simulation of the drilling process. Data from the drilling operation are processed real-time and includes drilling parameters, logging while drilling data, and other measurements performed during drilling. The base for a real-time update is pre-drill pore pressure predictions from basin modeling using Monte Carlo analysis. As drilling and log data becomes available during the drilling operation, fast calculations of pore pressure along the well are performed. The calculated pressure along the well is used to weight the pre-drill Monte Carlo results in order to update the pore pressure prediction ahead of the bit.

Real-time updated pore pressure predictions are of vital importance for advanced computer based systems for online supervision and decision support during drilling. Early warnings can be supplied if abnormal overpressures are to be expected ahead of the bit, or if measures should be taken to avoid dropping below the pore pressure. This paper presents the methodology and simulation results using log data from the Norwegian North Sea. Simulations show that pore pressure predictions ahead of the bit are improved compared with the pre-drill predictions, when updating predictions using the drilling logs.

The novel combination of automatically updated pore pressure data during drilling with an advanced real-time integrated drilling simulator provides a powerful tool for next generation drilling software.
Stochastic Modeling of Objects Extracted from High-Quality Seismic Data
Authors: Syversveen A. R. , Hauge R. , Tollefsrud J. I. , Lægreid U. , MacDonald A.
Published: October 2009

In this paper we present an approach for modeling facies bodies based on detailed seismic interpretation of the reservoir's sedimentological architecture. The approach involves the use of a highly constrained stochastic object model to integrate directly the seismic facies interpretations in a 3D reservoir model. It fills the gap between the use of seismic data in a true deterministic sense, where the facies body top and base are resolved and mapped directly, and stochastic methods where the relationship between seismic attributes and facies is defined by conditional probabilities.

In the new approach the lateral geometry of the facies bodies is controlled by seismic interpretations on horizon slices or by direct body extraction. Facies body thickness and cross-sectional shape are defined by a mixture of seismic data, well data and user defined object shapes. The stochastic terms in the model are used to incorporate local geometric variability which is used to increase the geological realism of the facies bodies and allow for correct, flexible well conditioning.

The result is a set of 3D facies bodies which are constrained to the seismic interpretations and well data. Each body is defined as a "parametric object" which includes information such as: Location of the body axis, depositional direction, axis-to-margin normals, and external body geometry. The parametric information is useful for defining geologically realistic intrabody petrophysical trends and for controlling connectivity between stacked facies bodies.