bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Effect of Microporosity on Transport Properties in Tight Reservoirs
Authors: Mehmani Ayaz , Tokan-Lawal Adenike , Prodanovic Maša , Sheppard Adrian P. 
Published: September 2011

Abstract
Diagenetic changes (e.g. cementation, compaction) in tight gas sandstones (TGSS) often disconnect the original, inter-granular pore space and further create microporosity within the original grains (e.g. by dissolution) or by filling the inter-granular porosity with clay. A petrophysically rigorous fundamental model of TGSS that accounts for microporosity would make the evaluation, development and stimulation of tight gas sandstone development more robust. The reduced connectivity of matrix pores has a profound effect on transport properties such as absolute and relative permeability, resistivity and capillary pressure - saturation relationships. To address this, we construct networks that incorporate both inter-granular (primary) porosity and microporosity, and use a network model to estimate flow properties. We present algorithms to geometrically match pore throat networks from two separate length scales that can be extracted directly from 3D rock images, or be constructed to match the relevant measured properties. Microporosity and its spatial distribution have a profound effect on the relative permeability curve. When inter-granular network is disconnected (but the microporous region is not), we provide capillary pressure - saturation curves in cases thus far unresolved with any other type of modeling. The results from model media reasonably match published experimental data. While we are motivated by TGSS, with suitable characterization the model is applicable to other reservoirs with dominant microporosity component (shale, carbonates).
Design and Examination of Requirements for a Rigorous Shale-Gas Reservoir Simulator Compared to Current Shale-Gas Simulators
Authors: Andrade Juan , Civan Faruk , Devegowda Deepak , Sigal R. F. 
Published: September 2011

Abstract
The necessary and sufficient conditions of the design parameters that should be considered to build proper shale-gas reservoir simulators are investigated. The design requirements are established based on the theoretical studies of flow through extremely low permeability porous media, ion milled SEM images of the nano-geometry of shale-gas reservoir formations, laboratory petrophysical measurements, and the available production and stimulation information. This paper presents a critical discussion of the relevant aspects such as the reservoir formation structure, fluid storage and transport mechanisms, and gradual non-equilibrium motion and dynamic distribution of fluids in the pore system. Then, an overview of the capabilities of the commonly used reservoir simulation software is presented in view of the identified requirements of shale gas reservoirs. Quantitative comparisons between the alternative formulations against the conventional formulations are also presented with several examples using an in-house simulator developed in this study. Areas needing new fundamental formulations and further research for proper shale-gas reservoir modeling are delineated. This paper provides important insights and guidelines for development of adequate numerical simulators that can correctly accommodate for the proper description of the relevant phenomena, and predict gas production and water displacement in shale-gas reservoirs.
Haynesville Shale Development Program – From Vertical to Horizontal
Authors: Abou-Sayed I. S. , Sorrell M. A. , Foster R. A. , Atwood E. L. , Youngblood D. R. 
Published: September 2011

Abstract
The recently discovered Haynesville Shale is one of the largest natural gas fields in the world. It is a high – temperature, high – pressure (HTHP), aerially extensive basin gas with true vertical depths (TVD) ranging from 10,000 – 14,000 ft; temperatures of 300 – 350+ deg F; and pore pressures exceeding 10,000 psi. It represents an engineering challenge unlike other popular shale reservoirs including the Barnett, Fayetteville, and Bakken shales.
In March 2008, EXCO started an aggressive development program in the Haynesville Shale reservoir on its East Texas/North Louisiana (ETX/NLA) acreage.
The program had a six-month window to select a landing zone and the appropriate drilling and completion techniques. Those techniques were then refined and applied to the horizontal well development.
The program included drilling six (6) vertical wells covering over 150 square miles to understand the reservoir rocks’ fracture properties and flow characteristics. It included whole cores; shale logging suites; hydraulic fracture design, operations, and diagnostics; chemical and radioactive tracers; flow-back characterization; diagnostic pressure testing and production evaluation.
At the conclusion of the vertical appraisal phase, EXCO spud its first horizontal Haynesville well in DeSoto Parish by drilling the Oden Heirs 30-6H well. The well's initial potential exceeded over 22 MMCFD @ 7,800 psi. This success encouraged the company to continue the development program resulting in 16 of the top 25 wells in the basin.
This paper outlines the program and the steps taken to achieve this accomplishment.
Well Performance Modeling in Eagle Ford Shale Oil Reservoir
Authors: Wang Jianwei , Liu Yang 
Published: September 2011

Abstract
Producing oil from shale oil reservoirs has gained attestations over the past several years. To efficiently and economically develop shale oil reservoirs, the impacts of hydraulic fracture parameters, hydraulic fracture induced complex natural fracture system, and rock characteristics to well performance need to be clearly understood. Numerical simulation based methods provided a better way over other conventional methods for modeling well performance in shale gas reservoirs, however it is still not clear if shale oil reservoir can be modeled using the same ways. We developed a simplified, coarse, dual porosity model to quick evaluate the effectiveness of stimulation treatment and understand shale oil production mechanism. Simulation results of a fine-grid reference model were compared with the simplified model to validate the new methodology. The simplified model greatly decreases simulation time and provides accurate results.
We applied this methodology to Eagle Ford shale oil wells. Historical oil, water, and gas production were matched for selected vertical wells. Reservoir and enhanced zone parameters were obtained after history matching, including OOIP, EUR, porosity and permeability of the matrix and natural fracture system, as well as half length, width, and permeability of the complex fracture network. Sensitivity analyses for horizontal wells then were conducted to quantify the impact of the reservoir characteristics and enhanced zone parameters, including net pay thickness, matrix porosity, permeability of the matrix and natural fracture systems, natural fracture spacing, half length, width, and permeability of the complex fracture network.
The simulation results indicate that the natural fractures permeability has the greatest impact on estimated ultimate oil recovery (EUR). Hydrocarbon pore volume (pay thickness and porosity) have the second greatest impact on EUR. The variability of matrix permeability has little effect on the oil recovery. The simulation results provided insights into effective stimulation designs and flow mechanism for shale oil reservoirs.
Advancements in Shale Gas Production Forecasting – A Marcellus Case Study
Authors: Thompson J. M. , M'Angha Viannet Okouma , Anderson D. M. 
Published: September 2011

Abstract
Arps Decline Curve Analysis (DCA) has been the standard for evaluating expected ultimate recovery (EUR) in oil and gas wells since the 1950's. Although this empirical method has served the conventional petroleum industry well, its misapplication to wells in ultra-low permeability plays, most notably shale, often yields ambiguous results due to invalid assumptions. Depending on the application of DCA, these forecasts, with constant hyperbolic decline exponent (‘b-value’) assumptions, have proven to be either overly optimistic or overly pessimistic. The applicability of the Arps method is limited to wells exhibiting boundary dominated flow. However shale wells exhibit transient flow for years, making them unsuitable candidates for the conventional approach of DCA. With the industry now focused on shale, new tools are required to help reduce uncertainty in well forecasts.
This paper presents a two-part study on the forecasting of shale gas well production. Part one utilizes a recently developed trilinear flow model (Ozkan et al. 2009) to improve forecast reliability while preserving simplicity for practical application. It is designed to account for 1) considerations of multi-fractured horizontal wells (MFHW), 2) improved localized effective permeability within the stimulated reservoir volume (SRV), 3) regional permeability contributions to the SRV and, 4) potential contributions of adsorbed gas to expected ultimate recovery. A workflow using this model is proposed and exemplified using production data from two gas wells from the Marcellus Shale (North-East Pennsylvania).
Although analytical models provide a deeper understanding of shale gas reservoirs as well as more reliable forecasting capability, Arps decline curves are, and will continue to be, the language of the reserves evaluation. That is why it is useful to understand the dynamic behavior of the decline exponent resulting from flow regime transitions during the transient period. Part two of this paper highlights an important consideration in the application of DCA to shale: the effect of desorption on the b-value. It will be shown that when desorption is invoked, the b-value will increase. This difference has been quantified for a MFHW in the Marcellus using a Langmuir adsorption isotherm representative of the region.
Consideration Factors in Defining an Effective Scale Management Strategy During Early Stages of Field Development Planning
Authors: Akuanyionwu Obinna , Wahid Fazrie 
Published: September 2011

Abstract
Developing a cost-effective scale management strategy as early as possible during field development planning is imperative to allow informed decision making. In the past, strategy selection was commonly based on static scaling risk assessment. However, the trend over the years has shifted to incorporate dynamic aspects, notably in-situ scale precipitation in a time lapse manner and coupling this with scaling risk assessments. More recently, streamline simulation techniques have been applied to support the prediction of scale precipitation in the reservoir and consequent in-situ stripping of scaling ions. It remains pertinent to extend the use of these dynamic tools to properly assess the impact of reservoir scaling reactions on scale management economics and the subsequent adoption of an optimum strategy.
A robust and systematic approach has been developed to combine the use of dynamic models in scaling risk assessment with envisaged production improvement processes and integration of disciplines in the decision analysis process. Reservoir scaling reactions are modeled using streamline simulation. Examinations have been extended to cover the impact of in-situ scale precipitation, taking into account changes in drainage radius in the presence of hydraulic fractures and different sandface completions. Emphasis is also placed on conducting analyses to address field complexities ranging from a variety of potential field development concepts, injection water alternatives, and drainage and completion options to uncertainties in formation water composition.
Workflows developed on a North Sea green field development are described, including results from analog/synthetic datasets as examples for this paper. Our work indicates that both in-situ ion stripping and drainage patterns significantly influence chemical requirements and treatment frequencies for squeeze treatments following in-situ scale deposition. Based on this information, comparative scale management costs are developed to help select the most appropriate scale management option. Finally, we highlight limitations in current industry tools and workflows and what can be done to reduce uncertainties during the development of a scale management strategy.
Sourceless LWD Service Provides Unique Petrophysical Measurements for the First Time in Offshore Environment: A Case Study from Libya
Authors: Meunier A. , Gonzalez-Munoz J. M. , Suarez Jaime 
Published: September 2011

Abstract
The continuous increase in demand for hydrocarbon resources has pushed the oil industry to look for additional recoverable resources in increasingly challenging environments. With new prospects, oil companies have to face new technical challenges everyday due to these conditions as well as stricter environmental and safety rules.
Offshore Libya is one of these challenging environments where drilling is high risk and where, for health safety and environmental (HSE) reasons, avoiding using radioactive materials in drilling and logging represents a great advantage by mitigating possible risks and costs. In order to overcome these new technical challenges and reduce cost, companies have to constantly evaluate new technology.
An advanced logging-while-drilling (LWD) platform that does not use a radioactive source provided a fully integrated advanced petrophysical evaluation capability, as well as a complete set of measurements to optimize drilling in a well in offshore Libya. To overcome environmental and safety constraints, the sourceless configuration provided a unique answer for formation evaluation in high risk drilling operations in offshore environments. A fully integrated real-time petrophysical analysis of data acquired while drilling thereby significantly reduced the need for additional measurements. This technology allows fulfillment of operational objectives by significantly decreasing the exposure to drilling risks and stuck pipe. This reduced
the time and cost required to properly characterize the reservoir and accommodate the strict regulations controlling radioactive material handling, without compromising the data completeness and quality.
The conventional EcoScope* technology has been used all over the world in offshore environment (especially in the North Sea). However, it is the first time the EcoScope* service has been deployed in an offshore drilling environment in its sourceless configuration.
High Speed Acoustic Telemetry Network Enables Real-Time Along String Measurements, Greatly Reducing Drilling Risk
Authors: Reeves M. E. , Camwell P. L. , McRory J. 
Published: September 2011

Abstract
A unique multi-node acoustic telemetry network capable of transmitting data at over 30 bits per second has been developed and successfully deployed in drilling applications.
This paper details the lessons learned and value derived from early use of the acoustic telemetry network while drilling medium radius build sections of multiple horizontal wells. Particular focus is given to discussion of overall network reliability, ease of well-site implementation and delivery of pressure data from multiple along-string measurement locations with or without fluid circulation.
Low latency, high-speed, real-time transmission of pressure data (from near the bit and other key locations along the borehole) allows highly accurate, potentially automated management of annular pressure to avoid unintentional formation fracture or fluid influx during drilling and non-drilling activities. This data can also be utilized to understand hole cleaning effectiveness in different sections of a well, allowing focused corrective action to be taken at the first sign of cuttings build-up, potentially avoiding costly stuck pipe incidents. In addition, continuous data transmission without the need for fluid circulation enables significant risk reduction when addressing well control incidents.
Highly reliable tools placed up to 2,500 meters apart establish the acoustic telemetry network within existing drill strings and in conjunction with all bottom hole assembly components. It is virtually transparent to all rig operations and, as a result, significantly decreases the implementation time and cost when compared to along string measurement solutions delivered by wired drill string technology.
This is the first publication of information from such field deployments and the first display of multi-node pressure data delivered via acoustic telemetry while drilling.
Re-assessment of Reservoir Dynamic Behaviour to Assist the Fourth Drilling Campaign in Mature, Geologically Complex North Sea Field
Authors: Valko I. , Moreau L.-P. , Coombes T. , Cooper R. , Troussaut X. 
Published: September 2011

Abstract
The Dunbar Field (UKCS, Block 3/14a), operated by Total E&P UK, is situated on an intermediate terrace between the East Shetland Platform and the Viking Graben and characterised by a series of pre-Cretaceous and structurally aligned tilted fault blocks. The principal hydrocarbon accumulations are contained in the Middle Jurassic Brent Group and younger Upper Jurassic Heather Sands.
Internally, the field is compartmentalised by a number of N-S faults and a secondary alignment of NE-SW faults which cross cut and often offset the main N-S faults. The larger scale faults down throw to the east and subdivide the field into four main areas; the West Flank, Central Panel and Frontal Panel with an uplifted Horst (Triassic) Panel in the south. Each of these panels has specific reservoir and fluid characteristics.
The Central and Frontal panels have a substantial production history of 15 years. The field is in steep decline with high water cut in water flooded areas, and extremely low pressure in compartments produced by natural depletion. A better understanding of recovery from the main flow units is essential for estimation of drainage volume, optimisation of water injection pattern and infill well placement/completion.
The ability to better define the size of the connected volumes through improved fault identification (Seismic PSDM3D Reprocessing) along with an improved understanding of the permeability field (sedimentological, petrographic, XRD, SEM, SrRSA, DST analysis & simulation studies) has been key in assessing Dunbar’s future potential. An intensive data acquisition campaign has been integrated in a comprehensive dynamic synthesis leading to a reservoir model history match that has improved our understanding of the field.
This paper describes the multidisciplinary team work leading to an improved understanding of the recovery efficiency and reservoir connectivity leading to a further drilling campaign.
Heavy Oil Offshore UK: Recommended Mariner Reservoir Development Strategy
Authors: Berg Eirik A , Reksten Kari , Scott Anthony Stephen , Ibatullin Tair , Møllerstad Hilde , Aasum Yngve , Julseth Lillian 
Published: September 2011

Abstract
The Mariner field - license 9/11 in the UK – was discovered in 1981 and is situated on the East Shetland platform. Mariner consists of two tertiary reservoir intervals of unconsolidated sand at depths between 1200 and 1500 mMSL. The deeper Maureen reservoir consists of stacked non-channelized sheet-like sand lobes deposited in a shelf to slope setting. The Maureen oil water contact (OWC) is stepping considerably and is shallower to the west. The Heimdal reservoir consists of deep-marine slope-channel sands within the mudstone-rich Lista interval, ranging in thickness from a few meters up to 40 m. The reservoir is heavily remobilised. The Heimdal OWC is uncertain with variable ODT (Oil Down To) observations and anticipated perched water. The total Mariner oil reserves are estimated to app. 400 MMBO (Million Barrels). The Maureen reservoir has 67 cp oil (14°API) in a 0–40 m oil column and a large bottom aquifer. The Heimdal reservoir contains two thirds of the reserves and has 508 cp oil (12 API).
Steady State SCAL studies indicate that Krw may be viscosity dependent. The Heimdal reservoir is planned to be developed using an inverted 9-spot well pattern due to uncertainty in mapping of the reservoir. The Maureen reservoir will be developed with horizontal wells. As the recovery factors are only 22%, Enhanced Oil Recovery using polymer is investigated as an upside to be matured towards production start. IOR through use of down-hole inflow control devises is progressed in a technical qualification program. OBC (Ocean Bottom Cable) data will be acquired to improve the mapping of the Heimdal reservoir.
Selection of Low Carbon Field Development Plans based on Lifecycle Energy Modeling
Authors: Mallinson Theo 
Published: September 2011

Abstract
Lifecycle energy modeling can be used as a primary design input during early project development. This requires a life of field facility model adapted to early concept design which allows operational costs and revenue collection to be considered against capital cost impact. Significant overall project savings can be discovered with this analysis even in cases where CAPEX impact is unfavorable. A design model based on a production depletion curve is used to set facility capacity requirements and to allow calculation of operational data such as yearly production achieved, fuel gas usage, carbon emissions value, and deferred production due to downtime. Production concepts can then be subjected to a quantitative analysis of external influences, such as effect of carbon emissions cost on project economics. A sensitivity case is developed using a production concept based on an all electric facility with major users (gas injection compressors and water injection pumps) employing variable frequency electric motors. Calculated carbon emissions, fuel gas usage, and expected availability for this case are compared against a base case utilizing discrete gas turbine drives. These lifecycle cost methods and analyses can supplement the conventional CAPEX focus during initial design phases of onshore and offshore facilities, a period in which some of the most important facility design decisions are made.
Fluid Composition Equilibrium; a Proxy for Reservoir Connectivity
Authors: Pfeiffer Thomas , Reza Zulfiquar , Schechter David S. , McCain William D. , Mullins Oliver C. 
Published: September 2011

Abstract
Assessing reservoir connectivity during the earliest stages of reservoir evaluation is highly desirable for successful field development. Nevertheless, it has long been problematic to assess reservoir connectivity prior to production. Recently, downhole fluid analysis has enabled facile assessment of fluid compositional gradients vertically and latterally. Using equations of state, the extent of fluid compositional equilibrium can be established. Only a process that stretches across the entire age of the reservoir is likely to capture geologic events that cause compartmentalization. Fluid composition equilibration requires mixing of the entire content of the reservoir which occurs only on the geologic time scale. Restrictive flow barriers are not compatible with thorough mixing of fluids throughout the reservoir. Fluid composition equilibration provides a tight constraint to test connectivity.
In this paper, the time constants for fluid composition equilibration are evaluated in numerical simulations. Equilibration processes are simulated in a simplified model over geologic timescales at isothermal conditions where diffusion and gravity are the active mechanisms. A variety of initial conditions and reservoir fluid types are considered. The effect of barriers on the equilibration time is investigated for single and multiple barriers. The results are compared with analytical calculations. Longer equilibration times correspond to tighter constraints on connectivity.
This work shows the progression of compositional gradients over geologic time until all components have reached zero mass flux. It investigates the foundation of connectivity studies that rely on fluid composition.
Determination of fluid equilibrium should become part of the standard procedure for reservoir connectivity evaluation.