bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Data Transmission Standard Facilitates Synchronous Remote Modeling and Surveillance via the Internet
Authors: Standifird W. , Baksh N. , Edwards S. , Wu V. 
Published: December 2007

Abstract
The communication of data between various operator and service company data stores has long been problematic. Fragile, low bandwidth lines of communication coupled with a lack of standards have left serious efficiency gaps in the movement of data from the acquisition location to decision-making and interpretation centers. Various systems have been developed and deployed to minimize these difficulties; however, all have fallen short of industry requirements. Recent availability of more robust, higher bandwidth lines between locations has led to a new standard of communication called Wellsite Information Transfer Standard Markup Language (WITSML). Using this new technology, data can be acquired and transmitted synchronously or asynchronously among multiple stakeholders with limited effort. The ability to mix and match various data collection vendors and connect these data sources to interpreters and modelers with limited effort is creating new opportunities to improve the success and efficiency of remote operations. This paper reviews four cases that demonstrate the use of WITSML to synchronously transmit real-time data from domestic and international offshore locations to onshore sites. The cases clearly demonstrate that WITSML meets previously neglected industry requirements of durability, flexibility, economy and ease of use in omni-directional data transmission between rig and shore.
Implementing Real-Time Asset Management: A Practical Perspective
Authors: Nordtvedt J. E. , Unneland T. 
Published: December 2007

Abstract
The Intelligent Energy domain is rapidly gaining attention within the oil and gas industry. Operators and service companies are currently transitioning from the initial envisioning phase to projects creating measurable value. However, there is still uncertainty regarding what needs to be done and what value it will actually bring. As a result, many assets experience organizational resistance to fully implementing efforts that can create value. This paper gives a practical perspective to field implementation of Real-Time Asset Management (RTAM) linked to the petroleum engineering work processes. We give practical illustrations and guidance on benefits from RTAM efforts including what work processes benefit most from integrating available technologies, and what steps are needed for implementing these in a RTAM setting. Examples are given to illustrate current challenges and success stories. Particular focus is on challenges and opportunities related to use of onshore operational centers, and how they will change the way we work in the future.
From Reservoir Through Process, From Today to Tomorrow—The Integrated Asset Model
Authors: Howell A. , Szatny M. , Torrens R. 
Published: December 2007

Abstract
Simulation technology from reservoir through process facility has advanced so much, that field development strategies can be developed within a new systematic workflow, using existing applications from many E&P departments. Detailed production data from many sources can be used within simulation models to give a good representation of future field wide behavior. In this paper a fictional case study of a reservoir that has been producing for some 12 years will be examined. The wells are all producing into a sub-sea manifold and then tied back via a 60km flow line and riser system. The reservoir is in severe decline with field production well below the original design capacity of the production system and surface facilities. Hence, further development options are being investigated for this asset. A new, nearby, reservoir has been discovered. A reservoir simulation model has been constructed for the new discovery. This second reservoir is a gas condensate system, much smaller than the existing reservoir and located 90 kms to the east. The current development plan shows six wells drilled and brought into production over an 18 month period. Reservoir 2 is a marginal development, the viability of producing this reservoir will depend on quantification of the reservoir uncertainty and finding a cost effective development strategy with existing processing facilities. The Business Development Team has suggested a number of possible options for developing this new reservoir; Option 1 involves tying in the new reservoir to the existing sub-sea infrastructure. Option 2 is to install a complete new flow line from the sub-sea template of the new reservoir and run this directly to the existing platform. But how do these options effect reservoir management and surface facilities performance? Evaluation is achieved by constructing an integrated asset model of the entire field, allowing the reservoir through facilities interaction to be evaluated in detail.
Gas Storage and Operations in Single-Bedded Salt Caverns: Stability Analyses
Authors: Han G. , Bruno M. S. , Lao K. , Young J. , Dorfmann L. 
Published: December 2007

Abstract
Bedded salt formations are located throughout the United States, providing valuable storage capacity for natural gas and other hydrocarbons. In order to increase gas storage capabilities and provide operators with improved geotechnical design and operating guidelines for these caverns, stability analyses of single bedded salt cavern have been completed and are described in this paper. This work is a part of integrated efforts initiated and sponsored by the US Department of Energy, Gas Technology Institute, and Pipeline Research Council International, Inc.
Numerical geomechanical models have been developed to investigate single cavern deformation and bedding plane slip for a variety of cavern configurations. A viscoplastic salt model has been developed based on an empirical creep law developed for the Waste Isolation Pilot Plant (WIPP) Program and combined with a Drucker-Prager model for damage and failure. The non-salt materials are described with either a traditional Mohr-Coulomb model, or an elastic model, depending on layer properties.
A baseline model with specified geometric dimensions is first selected and subjected to one year cyclic pressure operations. The amount of damage around the cavern wall and roof is evaluated and used as a comparison in the study. Then the operations are extended to 15 years to study cavern stability for long term gas storage and operations. In addition to the baseline model, parametric studies have been performed to investigate cavern damage as a function of salt roof thickness, overburden stiffness, interface properties, and cavern geometries. Each cavern simulation includes one year of pressure cycling with a minimum, mean, and maximum cavern pressure of 6.1 MPa (884.5 psi), 8.8 MPa (1276 psi) and 14.9 MPa (2160.5 psi), respectively. Different operation conditions, e.g. hydrostatic, cyclic, and a direct pressure drawdown, are compared and evaluated in terms of cavern stability.
These analyses can serve as a basis to select the best salt cavern candidate for gas storage and operations. They can also help to assess critical cavern design parameters for thin bedded salt formations.
3D Simulation of Rock Breakage With Air Hammers in Gas-Well Drilling
Authors: Han G. , Bruno M. S. , Dusseault M. B. 
Published: December 2007

Abstract
Air hammers have been used to drill gas wells in West Canada and Central USA since 1980s. Field evidence has demonstrated air drilling can be significantly improved with hammer bits in terms of Rate of Penetration (ROP), hole geometry, cost per foot, etc. However, inconsistent results in different formations, risks in operation, and economic uncertainties impede hammer acceptance and development.
In an effort to improve understanding of drilling physics and predict hammer performance, a 3D numerical simulator of air hammer drilling is developed in this study. The main features include an elastoplastic material model for rock constitutive behavior, a rock damage model for strength reduction and damage accumulation because of cyclic hammer impacts, multiple rock failure criteria for initiation of rock breakage, rock dynamic characteristics for energy dissipation and non-reflective boundaries. The numerical tool is further calibrated with the results from a series of single impact tests.
The simulation describes how rock behaves during the drilling, including stresses propagation inside the rock, deformation and damage evolvement, and breakage occurrence. It produces an estimation of ROP for different hammer energy and formation properties. The records of rock failure history indicate aggressive tensile failure may be primarily responsible for rock breakage in air hammer drilling, while compressive failure (or shear failure) may only contribute as a minor player.
These developments advance the simulation technology of hammer drilling and improve fundamental understanding of the physics involved. More importantly, the simulator can serve as a new tool to achieve a more predictable hammer performance.
Improving Storage and Workflow of Pressure-Related Information—Don't Lose Your Expert Community
Authors: Purdy C. , Webster J. , Brady K. 
Published: December 2007

Abstract
The next ten years are critical for managing manpower in the upstream petroleum industry. As experienced technical resources retire at an ever-increasing rate, companies are waking up to the reality that years of work and millions of dollars worth of knowledge and expertise is walking out the door.
In many companies, one person or a small community of experts are the only resource focusing on a particular discipline, such as pore pressure analysis or geomechanical modeling. Companies that have not developed or implemented solutions to combat the retirement challenge will be at a growing competitive disadvantage.
Factors surrounding data workflows and storage of pressure-related information within operating teams have been examined and show that data inaccessibility and inefficient data workflows have cultivated an environment where technical resources are unable to fully capitalize on available data. The current work environment does not allow past work to benefit current efforts and these factors are all at play in an industry that demands data sharing, collaboration and cross discipline cooperation.
By using existing technology and improved workflows it is possible to protect and benefit from the efforts of the retiring technical resources while improving the flow of information to the end user.
These storage and workflow challenges are reviewed for the pore pressure and geomechanical disciplines to demonstrate how better storage and data management translates into improved workflows and greater efficiencies among engineering and geological teams.
EOR Survey in the North Sea
Authors: Awan A. R. , Teigland R. , Kleppe J. 
Published: December 2007

AbstractThis paper provides a summary and a guide of the Enhanced Oil Recovery (EOR) technologies initiated in the North Sea in their period from 1975 until today. The five EOR technologies which have been initiated in the North Sea were hydrocarbon miscible gas injection, WAG injection, SWAG injection, FAWAG injection and MEOR. Each EOR technology which has been initiated in the North Sea was identified with its respective maturity level and / or maturing time frame, technology use restrictions and process efficiency on the basis of incremental oil.Apart from WAG at Ekofisk and FAWAG at Snorre CFB, all technologies have been applied successfully on the corresponding fields. Hydrocarbon miscible gas injection and WAG injection can be considered as mature technologies in the North Sea. The most commonly used EOR technology in the North Sea was WAG and recognized as the most successful EOR technology.The main problems experienced were injectivity (WAG, SWAG and FAWAG projects), injection system monitoring and reservoir heterogeneities (hydrocarbon miscible gas injection, WAG, SWAG and FAWAG projects). About 63% of all the reported EOR field applications have been initiated on the Norwegian Continental Shelf, 32% on the U.K. Continental Shelf and the remainder on the Danish Continental Shelf. Statoil was the leader in conducting EOR field applications in the North Sea. In the future, the majority of research will be conducted on microbial processes, CO2 injection and WAG (including SWAG) injection schemes.In this review laboratory techniques, world statistics, simulation tools and economical evaluation was not considered and is outside the scope of this paper.
Implementing Chevron's i-field at the San Ardo, California, Asset
Authors: Ouimette J. , Oran K. 
Published: December 2007

Abstract
This is a case study of an integrated "digital oilfield" project. The San Ardo, California, i-field Project is one of a number of current Chevron i-field implementation projects. It seeks to transform how the San Ardo steamflood is operated, focusing on better decision making for the asset and streamlined work processes for heat, wells, and water management. The San Ardo i-field project is nearing the end of the planning and front-end engineering phases, with project execution starting in 2006. The project team created preferred alternatives for transforming 21 work processes. Decision support software would be integrated with improved instrumentation, workflow automation, and data architecture to enable more reliable and efficient field operation and execution of reservoir management targets. The project is integrated in two ways. First, integration occurs across the asset management value chain from reservoir through production optimization to day-to-day steamflood and facilities decisions and work processes. Secondly, it is integrated across technology. For example, reservoir surveillance signposts are created and used with computer models to move day-to-day decisions along correct trajectories for executing reservoir heating and production management. A common collaboration and visualization environment would be used for executing day-to-day field decisions. The knowledge provided in the paper would be helpful for assets where field operators are managing many wells with limited resources and attempting to improve their operability and efficiency.
Horizontal Wells Drilling in Vertical Lateral Beddings Successfully Tap the Upside Remaining Oil in Heavy Flooded Sandy Zones
Authors: Liu Bing , Sui Xinguang , Zhao Minjiao , Wang Jiaying , Ma Chi , Yu Xinghe 
Published: December 2007

Abstract
PI reservoir, the main reservoir of Daqing oilfield has an average thickness of 15-25metres with one-third OOIP of the total. This reservoir is highly flooded that their daily oil productivity is 4-5 tons /d per well, with a water-cut of 95%. But the current recovery degree of OOIP is only about 40 %, and one-third of the top thickness has not been tapped. Injected water circulating along the big channels can not further enlarge swept volume. In recent years, we drilled horizontal wells to recover the top remaining oil in the reservoir. Since muddy intercalation seldom develop within channel sand, this often results in fully flooded in horizontal wells by fast water breakthrough from the bottom to the topside of the reservoir as top remaining oil is produced.
This paper describes reservoir with geological model, and shows the internal architecture in the reservoir accurately. We use lateral muddy intercalations as barrier beds to prevent vertical flood along the wellbore, Once flood occurs, we perform water-plugging in specific lateral beddings. Let's take well N1-H25 for example, it was designed as a horizontal well with vertical lateral beddings. It was brought into production in Dec., 2004, initially it produced 123 tons per day, which was 22 times the production of any well in the same formation. In July 2005, its daily oil production was 81 tons, with a low water-cut of 28.9%. It has accumulated 26000 tons of oil by Dec. 2005. This well was designed to pass 8 lateral beddings, but in fact, it passes 16 lateral beddings. Its lateral muddy intercalation successfully prevented water flood along the wellbore, and effectively produced potential remaining oil in top highly flooded sand reservoirs.
Intelligent Monitoring? …. Add Borehole Gravity Measurements!
Authors: Loermans T. , Kelder O. 
Published: December 2007

Abstract
Borehole Gravity Measurement (BHGM) tools have been available for several decades, but until now, widespread applications were not possible. The current BHGM tools are too bulky to be run in almost any well without pulling the tubing. In addition, BHGM tools are limited to vertical wells and the existing sensors fall short on stability for permanent installation.
BHGM tools could be very useful for reservoir and production monitoring. First, the depth of investigation is enormous when compared to many other measurements. Advancing flood fronts, not only gas-water but even oil-water, could be detected from a distance of tens, hundreds or even beyond thousand feet from a well, if suitable BHGM sensors were available. Second, only very few parameters are needed to convert the raw gravity measurements, via a bulk density, to the main output: saturation. This avoids the challenges with several special parameters which are needed to arrive at saturation when using resistivity logs. Third, the interpretation models are simple: for gravity interpretation Newton's laws are perfectly adequate, while for resistivity and acoustic measurements, research on response functions is still ongoing.
We have modelled the response of BHGM tools in a number of typical Saudi Arabian conditions, including advancing oil/water fronts, coning and near well bore monitoring, proving the significant potential for BHGM technology. Hence, as there is a need for improved production and reservoir monitoring, further BHGM development becomes very attractive.
From an analysis of current day gravity sensors, several possible further development routes can be painted, each with its own advantages. It is clear that if our industry desires additional monitoring capabilities, it will be relatively simple to achieve intelligent monitoring by selecting the most appropriate route and developing those BHGM sensors, tools and related systems.
Three-Phase Upscaling in Capillary and Viscous Limit
Authors: Lohne A. , Virnovsky G. 
Published: December 2007

Abstract
Three phase flow properties are important for correct modeling and prediction of such IOR processes as WAG and blow-down/depletion after waterflooding. On the core-scale, these properties can generally be obtained directly from experiments, from pore-scale modeling of three-phase flow, or from empiric formulae (like the Stone's) interpolating two sets of two-phase data into the three-phase saturation region. For usage in simulators core scale properties have to be scaled up to reflect heterogeneities smaller than the simulation grid-blocks. These upscaled three-phase properties, similarly to their two-phase counterparts, are rate-dependent. We describe the upscaling procedure and efficient algorithms for three "easy-to-compute" asymptotic cases: VL-viscous limit (viscous dominance), CL-capillary limit (dominance of capillary forces), and VE-vertical equilibrium (flow dominated by gravity and capillarity).
Upscaled 3-phase relative permeabilities for different geological flow units from a North Sea field are analyzed. At VL, upscaled relative permeabilities to all phases will in general depend on two saturations if contrasts in relative permeabilities are present at the finer scale. This dependency may in many cases be small and ignored, but not always.
At CL, upscaled krw and krg will remain functions of one saturation each, as long as the oil phase is mobile in every part of the porous medium. When oil reaches its immobile saturation in part of the medium, both krw and krg will turn into full three-phase functions depending on two saturations. For the examples presented the size of the domain with full three-phase functions covers up to about half of the three-phase domain. The three-phase dependency was very weak for water in all the tested cases, while for gas very strong effects could be observed.
Efficient History Matching in Naturally Fractured Reservoirs
Authors: Gang T. , Kelkar M. 
Published: December 2007

Abstract
For naturally fractured reservoirs, history matching requires that both the matrix and fractures are properly characterized. Log and core data as well other static information can be very useful in building the matrix model. Some elements of the fracture model can be built using 3-D seismic data, well test data and production logging tool (PLT) data. However, field experience suggests that it is very difficult to properly quantify fracture permeability without matching production data. Currently, the procedure involves a trial and error method, where fracture permeabilities are adjusted manually to match the production data including water cuts and breakthroughs. One can adjust other parameters to match the data; however, fracture permeability (especially in the presence of large permeability contrast between matrix and fracture) represents first order effect in matching the production data.
This study focuses on the automatic history matching of production data by adjusting fracture permeablity in a static model. The methodology not only ensures geological consistency in the final model, but also includes uncertainties about fracture locations. The calculation of the sensitivity of the production data such as bottom hole flowing pressure, WOR and GOR etc. to reservoir model variables such as gridblock effective permeability, porosity and fracture/matrix coupling factor etc. is made efficient by an efficient direct sparse solver. Through building the relation between the fracture permeability and the reservoir model variables, the gradient of the production data to fracture permeability was estimated by chain rule. Through the transformation of reservoir model variables into the fracture permeability space for history matching, a significant time has been saved because of the reduction in parameter space.
The method is validated by conducting history matching for both synthetic and field data sets. The results show that this method is reliable and efficient for naturally fractured reservoir history matching.