bluuebunny/crossref_metadata_2025 huggingface dataset:
Integrated Use of Natural Gas in Rural China
Authors: Economides Michael J. , Wang Xiuli
Published: February 2011

For China to reach a semblance of a developed country's energy profile is perhaps the biggest social and economic challenge of the world today.

China's challenges are formidable and they fall into three categories. The first is to find adequate supply to meet the large current and even larger future demand. China does not have sufficient indigenous resources and will have to import and therefore compete with other countries, such as Europe, for Russian gas. The second is China's energy makeup which is still very primitive (70% of China's energy comes from coal, a share that the West has not seen since the nineteenth century). This affects pollution, emissions, and efficiency. The third is geographical distribution with very large imbalances between the rural and urban populations of China.

Natural gas, which currently accounts for less than 4% of China's energy mix but is in great abundance internationally, must increase at least by an order of magnitude in a fast pace. Natural gas offers the only hope as a pollution-acceptable fuel for power generation and, very importantly, as a motor vehicle fuel. Currently, the Chinese use approximately 35 times less natural gas per capita than that used in Western Europe or the United States. Also we estimate that 80% of the Chinese public has no access to natural gas either directly or indirectly.

With this situation, we offer different forecasts of the energy future and present scenarios for natural gas distribution in China by making use of a navigable river. We take into account existing systems and estimate the required infrastructure to bring minimum natural gas (e.g., 30% of natural gas per capita use in the United States) to 80% of Chinese people.
Optimum Injection Rate of A New Chelate That Can Be Used To Stimulate Carbonate Reservoirs
Authors: Mahmoud M. A , Nasr-El-Din H. A. , De Wolf C. A. , LePage J. N
Published: February 2011

Different chelating agents were used as alternatives for HCl in matrix acidizing to remove near wellbore damage and create wormholes in carbonate formations. Previous studies have demonstrated the use of ethylenediaminetetraacetic acid (EDTA), hydroxy ethylenediaminetetraacetic (HEDTA) and glutamic acid-N,N-diacetic acid (GLDA) as an alternative for HCl to stimulate carbonate reservoirs. The main problem with EDTA and HEDTA is the low biodegradability.

GLDA was introduced as alternative for HCl for stimulating deep carbonate reservoirs at which HCl will cause corrosion and face dissolution problems. In this study calcite cores, 1.5 in. diameter with 6 and 20 in. length were used to determine the optimum conditions where the GLDA can breakthrough the core and form wormholes. GLDA solutions with pH values of 1.7, 3, and 3.8 were used. The optimum conditions of flow rate and pH were determined using the coreflood experiments. CT scan was used to determine the wormholes length and diameter to determine of optimum Damkӧhler number. GLDA was compared with chelates that are used in the oil industry such as EDTA and HEDTA. GLDA also was used to stimulate parallel cores with different permeability ratios (up to 6.25) to assess its ability on diversion.

GLDA was found to be very effective in creating wormholes at pH = 1.7, 3, and 3.8 at different injection rates at temperatures of 180, 250, and 300°F. Increasing the temperature increased the reaction rate and less amount of GLDA was required to breakthrough the core and form wormholes. Unlike HCl and EDTA, there was no face dissolution or washout in the cores even at very low rates. Also, an optimum flow rate and Damkӧhler number were found at which the pore volume required to create wormholes was the minimal. GLDA at pH 1.7 and 3 created wormholes with a small number of pore volumes. Compared with acetic acid the volume of GLDA at pH 3 required to create wormholes was less than that required with acetic acid at the same conditions. GLDA was found to be effective in stimulating parallel cores with different permeabilities.
Reverse Osmosis Compatible Chemical Foamers For Gas Well Deliquification And Production Enhancement
Authors: Willis Martin J. , Conrad Greg A.
Published: February 2011

In times of increasing energy demand the need for more natural gas is greater than ever. To address this demand there are many drilling campaigns of coal seam gas (CSG) wells to supply the new liquefied natural gas (LNG) plants. Typically, within these wells progressive cavity pumps (PCP) are used to unload water to facilitate gas production. The produced water is then commonly processed by reverse osmosis (RO) to provide water suitable for re-use in other industries.

Previously PCPs were the only feasible pumping option, due to the presence of particulates, which is a relatively expensive deliquification method. Nalco has developed an alternative artificial lift method in the form of a liquid chemical foamer. This method offers cost efficient lift that will support initial liquid unloading as well as aid liquid management to maturation, enhancing lifetime production and lowering operating expense. In addition the technology offers secondary benefits for corrosion management, improving potential asset longevity.

The chemical has been demonstrated to perform in typical CSG brines and in the presence of coal fines, however the significant technology breakthrough is the compatibility with the RO membranes. Conventional foamer surfactants are incompatible and compromise safe, efficient unit operation. The laboratory and field data to demonstrate these claims is presented within.

To further enhance the technology offering a total deliquification approach has been developed, combining the chemical with a patented injection system. Appropriate steps have been taken to ensure the chemical is compatible with the injection system hardware and operating conditions, and most importantly benefits from the novel atomizer valve. In comparison to standard injection valves significant gains have been recorded in the field circa. 30%. The process of well selection, hardware installation, chemical treatment and monitoring is detailed within the paper.
Physical Water Treatment in the Oil Field: Field Results from Indonesia
Authors: Muswar Heppi , Parker Wiley , Falsini Francesco , Thaib Dirasani
Published: February 2011

Oil and gas wells in the Wampu field in Indonesia are plagued with carbonate scale depositsi. These deposits interfere with efficient oil and gas production from these wells and limit their profitability. Electromagnetic physical fluid treatment is a new strategy for controlling deposits and this paper describes both the theory behind the treatment strategy and the compares results of 18 months of application on wells in this field with that previously seen. Comparison results will be presented from wells in North America.
Who Gets to Be Boss? … addressing demographic pressures within the petroleum industry
Authors: Lau Richard A. , Hasani Nadia Al , Lau Laura , Eide Constance
Published: February 2011

abstract

From the day in 1859 that Edwin Drake drilled the first oil well in Titusville, Pennsylvania, English has been the lingua franca of the petroleum industry. As the quest for oil escalates into all areas of the world and as solutions to the world's energy needs become more complex, national and international oil companies compete to employ the best and brightest to ensure that the flow of precious hydrocarbons remains unabated.

The Abu Dhabi National Oil Company (ADNOC) in the United Arab Emirates (UAE), a state-owned petroleum producer that boasts some of the largest known oil reserves on the planet, perpetually finds it difficult to employ enough qualified English-speaking staff to manage its petroleum exploration, production, and distribution subsidiaries. Concerned about its inability to fill positions locally, ADNOC has attempted many local initiatives and has even been compelled to provide scholarships for Emirati citizens to be educated in institutions of higher learning in North America, Europe and Australia. Nevertheless, this national oil company has been forced to import expensive, qualified engineers from abroad. (Geologists, 2008).

Grateful for employment as well as a safe environment to raise their families, many of these foreign engineers have remained and prospered in the UAE while accepting second-class status in a land they can never really call their home. Many of these professionals are now clamoring, however, for opportunities for their own children to be able to remain and become educated into the petroleum professions on a fairer footing.
Systematic Team Approach to Product Development Delivers Massive Performance Improvements in the Horn River Shale Gas Play
Authors: Barton S. P. , Lockley J. R. , MacLeod A. M.
Published: February 2011

The Horn River Basin is a natural shale gas play located in North Eastern British Columbia, Canada. However, these wells require advanced horizontal drilling techniques and extensive hydraulic fracturing to make them economically attractive. This paper details how a major operator, working in cooperation with a key drill bit supplier, has been able to make radical improvements in drilling performance in this area, leading to significant cost reductions.

A typical well consists of a main hole interval that has a vertical section, build section (taking the bore from vertical to horizontal), and a final horizontal leg. When the operator started this project in 2008, the objective was to drill this entire main hole in just three bit runs; one for each directional leg described prior. In actuality, twelve to fourteen bits were utilized, averaging over forty days from drill-out to section TD. This made the economic viability of further development questionable.

The team approach of operator and bit supplier enabled bit design modifications and improvements to be implemented in a controlled, continuous, and closely monitored program. A key component of this was the development of a unique flexible bit design developed specifically for directional applications in coordination with a leading supplier of motors. These bits contain novel features that allow rapid design modifications to be performed locally, significantly reducing response time, and allowing the program to proceed at a much faster pace than previously possible. Prior to any alterations, a full analysis of the drilling data of the previous iteration was undertaken. Any proposed changes were then discussed in detail with the drilling operations team, prior to implementation.

By July 2009, this systematic cooperative approach enabled the operator to achieve the initial objective of drilling the interval in 3 bit runs, but also their subsequent objective of drilling the interval in just two bit runs. Days to drill this section were drastically reduced from over forty to less than twelve days. The savings produced by this huge improvement in drilling performance has greatly assisted the economic viability of continued Horn River Basin development.
Electronic Rollerboard in Dispersed Engineering Execution
Authors: Soman Bhavna
Published: February 2011

The Electronic rollerboard (ERB) is a network based tool which allows users located in different offices across the globe to view, review and add comments to a document/drawing during the execution of a project. It delivers upto-date information to all involved. This paper talks about the various features of ERB and how they enable multiple offices to better execute projects together, by providing everyone with up-to-date information. It discusses how the ERB streamlines communication, which in turn facilitates change management, leading to better scheduling, and thus, significant savings for a project. The challenges in its setup and application to a project, shortcomings, and areas for future improvements are also addressed. This paper also shares possible software platforms through which the ERB can be implemented, and experiences from using it on a project.
Integrated Operation User Experience Starts with Data Flagging
Authors: Flichy Philippe
Published: February 2011

Complaints about the usability and trustworthiness of data along with their proper reconciliation and consistency checks have been an ongoing source of frustration to the effective adoption of the Digital Oil Field. Valid data is just the first step in the Digital Oil Field (DOF) data supply chain; once the data has been validated, it must then be properly stored (again), transmitted, accessed, and then displayed appropriately and in context.

This is where standards like PRODML play a pivotal role in facilitating multivendor applications interconnection. Until we have a better approach for validating and accessing the massive amount of data generated by new sensor technologies, we cannot reap the true benefit of either the technologies or processes of the DOF.

This paper attempts to highlight some similarities in the challenges other industries, such as aerospace and defence, are facing compared to O&G in terms of real-time data capture, visualization, and how are addressing them.
Capillary Trapping in Water-Wet Sandstones: Coreflooding Experiments and Pore-Network Modeling
Authors: Pentland Christopher H. , Tanino Yukie , Iglauer Stefan , Blunt Martin J.
Published: February 2011

Displacement experiments using the porous plate method were conducted on water-wet sandstones to measure the capillary trapping of oil by waterflooding as a function of its saturation after primary drainage. Three sandstone samples ranging in porosity from 12.2% to 22.1% were considered. Experiments on two samples were conducted at an elevated temperature and back-pressure of 343K and 9MPa respectively; experiments on the third sample were conducted at ambient conditions (292 to 297K and 0.06 to 0.17MPa). Residual oil saturation increases monotonically, but with a decreasing gradient, as initial saturation increases.

The dependence of residual saturation on initial saturation is accurately predicted by a two-phase pore-network simulator when a uniform distribution of intrinsic contact angles between 35° and 65° is assumed. The networks were extracted from X-ray microtomography images of small samples of the same rock as those used in the experiments. The laboratory measurements are also accurately described by trapping models proposed by Land (1968) and Spiteri et al. (2008). The residual saturations we measured were higher than in previous displacement experiments, suggesting, for example, that capillary trapping may be an effective way to store substantial quantities of carbon dioxide in aquifers.
Returns Matching Reveals New Tools for Fracture/Reservoir Evaluation
Authors: Gdanski R. D. , Fulton D. D. , Johnson B. J.
Published: February 2011

Evaluation of fracturing treatments in tight-gas sands is frustrated by uniqueness problems when matching gas rates and bottomhole-flowing pressure (BHFP) data alone. A fit-for-purpose simulator was used to match gas rates, BHFP, cumulative produced water, and composition of the water during five days of cleanup after a fracturing treatment. The simulator models physics of flow and chemical physics to provide improved history matching of the cleanup process. Downhole gauges were in place during cleanup and a 16-hour, shut-in period. History matching of the well returns data with the fracture cleanup model provided multiple solutions when matching gas, water, and BHFP. These solutions all fell on a “line-of-solutions” using a special plot of reservoir properties vs. conductive length. Pressure transient analysis (PTA) of the gas rate and BHP during cleanup and buildup provided solutions that also fell on the same “line-of-solutions.” A “root-of-time” plot of the 16-hour buildup indicated a fracture of infinite acting conductivity and no fracture face-skin damage. A “productive proportion” plot of the simulated fluid recovery vs. the ratio of conductive to created length was used to help narrow, or break, the uniqueness problem in the line-of-solutions. These tools demonstrated that the conductive length was roughly 400 ft. The reservoir permeability to gas was much lower than expected and was the cause of the disappointing productivity. This work demonstrates that matching well-return compositions with a fracture-cleanup model capable of chemical physics can lead to improved interpretations of both reservoir properties and fracture structure. Three new graphical tools provided compelling evidence for the interpretation, and should have significant value in future evaluations.
Costs of CO2 Transport and Injection in Australia
Authors: Neal P. R. , Hou W. , Allinson W. G. , Cinar Y.
Published: February 2011

This paper reports estimates of the costs of CO2 transport and storage across Australia. The estimates were commissioned as part of the work of the Australian Government's Carbon Storage Taskforce. Using data provided by government departments and industry, we investigated combinations of nine emission hubs and twelve storage basins. We also developed a first-pass method for estimating numbers of injection wells using numerical reservoir simulation and comparisons with actual CO2 injection projects.

This work forms part of a suite of studies intended to help formulate government policy on carbon capture and storage. Our analyses are aimed at helping industry and government to plan carbon abatement strategies by indicating regions likely to have lower deployment costs for CO2 transport and injection.

We present engineering and economics results for projects across Australia and rank storage basins by cost. The cheapest cases store CO2 from the Latrobe Valley in the Gippsland Basin (A$7 per tonne of CO2 avoided), from Southern Queensland in the Surat Basin (A$ 12 per tonne) and from the Perth region in the Bunbury Trough of the Perth Basin (A$10 per tonne). We include sensitivity analyses examining the effects on project costs of monitoring and exploration costs. We also show the results of analyses of the effect of exploration risk.

We provide recent estimates of CO2 transport and storage costs for potential projects across Australia on a consistent basis. These illustrate the importance of various geological characteristics in determining the CO2 injection cost, and report the relative costs of exploration, equipment, construction and monitoring. Finally we describe a quick and efficient first-pass technique for estimating well numbers.
Crosslinked Acid as an Effective Diversion Agent in Matrix Acidizing
Authors: Runtuwene Michael , Fasa Muhammad Hilmi , Rachmawati Fitria Dewi , Wijanarko Muhammad , Kadarsyah Arief , Komalasari Novi , Gurnito Nuratas
Published: February 2011

Matrix acidizing has been a successful stimulation method to enhance production in carbonate reservoirs. One of the challenges is to distribute the acid evenly along the interest zone to achieve a maximum stimulation effect, due to the differences in porosity, permeability and degree of damage along the interest zone.

Well-S delineation gas well, located in Senoro Field Sulawesi-Indonesia, is drilled through a carbonate reservoir. It was decided to use an acid soluble diversion agent instead of conventional proppant. This diversion agent is an acid system that contains a polymer that crosslinks as the acid spends to near completion, with this crosslink then disappearing as the acid spends more completely over time. The non-crosslinked spent acid can then be flowed back from the formation with relative ease.

Acid solubility test for 15% HCl and crosslinked acid was performed to design the acid job and the result showed that Senoro carbonate has 90% solubility. This crosslinked acid serves as a diversion agent that will facilitate the acid to be evenly distributed along the interest zone. The well test result before stimulation was 13 MMSCFD gas with skin value of +3 (obtained from PBU test), while permeability was 4 md. The well was tested again after stimulation. Significant increased gas rate was observed while the skin damage decreased.

This paper describes the planning and implementation of crosslinked acid application as an effective diversion agent in long interval matrix acidizing stimulation. Furthermore, it explains the criteria to determine the efficiency of this application.
Formation Evaluation Challenges in Thin Bedded Reservoirs: How to Effectively Test This Formation?
Authors: Kiatpadungkul Wiriya , Daungkaew Saifon , Athichanagorn Suwat , Azam Mohd Nor , van Doorn Jurry , Haddad Sammy
Published: February 2011

Thin beds are a prominent feature in many recently discovered hydrocarbon reservoirs around the world. Not only are they typically difficult to evaluate, which leads to high reserves uncertainty, they are also frequently associated with inconsistent well performance. One of the main challenges in the evaluation of thinly-bedded reservoirs is an accurate productivity assessment. High-resolution borehole image logs provide us with detailed information on the internal structure of reservoirs sands, sand quality indications as well as a net-to-gross determination. Reliable formation evaluation requires further high-resolution petrophysical and geophysical logs (for an initial permeability estimation, free fluid volume, saturation, formation anisotropy and structural information). However, as per reservoir testing information (pressure, fluid types, PVT properties, permeability and producibility), this dynamic reservoir characterization method needs to be properly planned and evaluated. In the past, the use of full scale Drill Stem Test and Production Tests were conducted to obtain reservoir parameters including zone productivity. However, due to costly operations especially in marginal and also deepwater reservoirs, different scales of pressure transient test have been introduced1, 2, and 3. Several publications have discussed the use of smaller scale testing to obtain reservoir information. However, there have been no publications showing a complete comparison of pressure transient data obtained from several scales of measurement when heterogeneity is present in the reservoirs.

This paper therefore aims to present a comparison of results obtained from alternative formation testing methods in a relatively thin (ten of meters) formation which are a single probe Wireline Formation Tester, dual packer Wireline Formation Tester, and full scale well test. This paper also discusses ways to optimise the testing methodology in such thin reservoirs. The application of an Interval Pressure Transient Test (IPTT) using a single probe as well as the dual packer WFT are illustrated and discussed in details. Their applications, specifications, advantages and disadvantages over the conventional testing method are extensively covered. This study aims to aid in devising suitable field development strategies at an acceptable cost while maintaining satisfactory operational efficiency.
Are Your Geoscience Applications Maintaining the Integrity of the Geospatial Data?
Authors: Barrs Barry , Davis Jonathan , Latef M Zukhairi , Michell Mark , Shostak Brian , Stigant Jonathan
Published: February 2011

The paper presents the results of a Joint Industry Project (JIP) to explore the integrity of the management of geospatial data in geoscience software applications (GIGS – Geospatial Integrity of Geoscience Software). The International Association of Oil and Gas Producers (OGP), Survey and Positioning (S&P) Committee administered the project; the members included 13 international O&G operating companies. The paper will be of interest and applicable to geoscience software architects and developers, geoscience software users, geoscientists, data managers and reservoir engineers and their respective asset and management teams. The JIP was formed to investigate the difficulties, experienced by both designers and users of geoscience software, of retaining the integrity of coordinate data when being processed, manipulated and interpreted in geoscience applications. The geoscience applications are being used to develop an understanding of sub-surface features from geophysical, geological, well log and other ancillary supporting data that have been loaded into the application. Clearly such information will lead to the placement of rigs to drill wells. The placement and subsequent management of these wells and the associated reservoirs are highly dependent on an accurate understanding and mapping of the data. This dependency is the primary motivation and driver for this JIP. The results of the JIP work are presented in the form of a new OGP guideline. The guideline contains geospatial requirements and recommendations with two associated annexes, providing a ‘roadmap’ to evaluate or review a given G&G application (annex 1), and a testing regime with an associated test dataset (annex2) to allow for such a review to be undertaken. An introduction, brief history, business case, and some examples of the guideline products, are included; these are to assist the reader in understanding the scope, the framework, the context and the potential impact of the work.
Low Salinity Waterflooding and Mineral Dissolution
Authors: Pu H. , Xie X. , Yin P. , Morrow N. R.
Published: February 2011

Numerous laboratory studies have shown that water composition can substantially affect oil recovery by waterflooding. Investigation of increased oil recovery by injection of low salinity water such as coalbed methane production water has been extended to reservoir cores from the Tensleep, Minnelusa and Phosphoria formations in Wyoming. The Tensleep and Minnelusa formations are eolean sandstones of comparable depositional environment that contain interstitial anhydrite, dolomite and occasional calcite cements. The Phosphoria dolomite has pin-point to coarse vuggy pores lined by sparry dolomite crystals and also features patches of anhydrite. All the cores taken from pay zones showed increased oil recovery ranging from 5 to 8% original oil in place through injection of low salinity water. Increase in sulfate ion content of the effluent brine confirmed the dissolution of anhydrite, for all three rock types. Proposed mechanisms of recovery by low salinity flooding of sandstones which are tied to the presence of clay cannot apply because none of these rocks have significant clay content. In addition to effluent composition, dissolution of anhydrite cement within Tensleep sandstone was previously demonstrated through pore level micro X-ray CT imaging. Further evidence of the role of anhydrite dissolution was provided by the recovery behavior of Tensleep cores taken from the water-saturated zones of an oil reservoir. Anhydrite cement was sparse and visible in occluded regions of pore space but not in regions that were clearly permeable. For these cores, there was no additional oil recovery when the injected brine was switched to low salinity water. The release of dolomite crystals and other fine embedded minerals which is likely associated with dissolution of anhydrite, may be a factor in the observed response to low salinity waterflooding. The movement of cement components is a possible contributing factor in the wide variety of observed relationships between pressure drop and oil recovery. For example, significant variation of relative permeability to brine at constant saturation is often observed.
Integration of 3D Seismic and Reservoir Simulation for Remaining Oil Exploitation in a Heavy Oil Field: A Case Study
Authors: Ling Yun , Huang Xuri , Guo Xiangyu , Cai Yintao
Published: February 2011

Based on a full azimuth 3D seismic (cell size 6.25m × 6.25m and coverage area 14 km2) and reservoir simulation on one well group (40 vertical wells and 5 horizontal wells in an area of 600m × 375m), integrated research on Steam Assisted Gravity Drainage (SAGD) production is carried out in an oilfield in Northeast China. The research indicated that the configuration of steam chambers caused by steam injection could be delineated from the high precision 3D seismic results, and it is more accurate than the reservoir simulation model in the local variation description of the chambers (the accuracy of the simulation model is influenced by density, porosity and permeability data). But with only seismic, it is difficult to differentiate the influence of geological sedimentation or small-size fracture from the steam chambers, and further predict the distribution of the remaining oil. By integrating the 3D seismic with a reservoir simulation model (thus forming a 3.5 D seismic method), we can predict the remaining oil. This approach is free from many technical difficulties facing time-lapse applications such as no baseline survey and non-repeatable noise.
Accelerating Progress Toward Achieving Digital Oilfield Workflow Efficiencies
Authors: Crawford Mark L. , Morneau Richard A.
Published: February 2011

The Upstream Oil and Gas Industry is working toward asset optimization through various Digital Oil Field of the Future (DOFF) programs. Significant progress has been made over the past few years, but the mission is not complete. The industry is still faced with challenges that inhibit system interoperability and in turn reduce workflow efficiencies. When one considers the software and data integration requirements to achieve the vision of the digital oilfield, one has to wonder if the Upstream Oil and Gas Industry will be able to maintain DOFF progress or if our advancements toward the digital oilfield may begin to plateau before we reach our objective. This paper considers the question "What are the key considerations to achieve the workflow efficiencies envisioned for the digital oilfield and how can we accelerate this process?" The authors probe the answer to this question by reviewing various IT-related standards activities, how they might improve workflow efficiencies, and the need for better coordination across standards development. The discussion will illustrate why the Upstream Oil and Gas Industry struggles with software and data integration. In conclusion, the authors will present thoughts around a path forward which they believe will help realize the industry's aspirations for the digital oilfield.
Water Hammer in Off-Loading Systems: Contribution of Detailed Modelling to Design and Safety
Authors: Pierre B. , Gudmundsson J. S.
Published: February 2011

The second largest oil spillage in Norwegian petroleum history occurred on December 12, 2007, when the Statfjord A offloading system ruptured. Results of numerical simulations of pressure transients in the off-loading system are presented. Of particular interest is the influence of acoustic properties of pipeline sections on propagation of pressure transients. The damaged off-loading system geometry and characteristics as well as the acoustic properties are described. The paper describes numerical simulations of pressure transients in the off-loading pipeline. The paper shows particularly how detailed modelling and accurate estimation of acoustic velocities influence local maximum increases in pressure in an off-loading system.
A Fully Compositional Integrated Asset Model for a Gas-Condensate Field
Authors: Gonzalez F. , Bertoldi L. , Lucas A. , Paterson G. , Shah K. , Grewal B. , Okafor C. , Rodriguez N.
Published: February 2011

A fully compositional Integrated Asset Model (IAM) has been built for a giant gas-condensate field. The field is a complex retrograde gas-condensate reservoir with a hydrocarbon column up to 1750m in height. The fluid composition varies significantly with depth, ranging from a gas condensate to under-saturated oil.

Production is centred on three processing facilities which are variously constrained by gas processing, gas compression & oil stabilisation capacities and overall export levels. There are some 100 producers and 15 gas injectors presently active in the field, with new wells and facilities planned as part of future development.

IAM's for the total production system have been gaining in popularity for applications such as FEED studies, field development planning and optimisation. Their complexity has grown with the need to have fully compositional models, which are particularly important for gas condensate fields, where accurate fluid description is required for predicting condensate recovery and injection gas composition.

Development of this IAM has required close cooperation between reservoir, production and process engineers since each of the component models - a 3D reservoir simulation model, production & injection surface network models and a process model for the three production units – are complex in their own right. The IAM model honours the well, network, and facilities constraints, taking into account interdependence between the different elements of the system.

The IAM provides the capability to manage scheduled field events (well re-routing, plant maintenance, field uptime, etc) and optimizing field liquid production.

This work offers valuable insights for more accurate assessments while evaluating different field exploitation strategies.
Kinetic Simulation of CO2 Flooding of Methane Hydrates
Authors: Phirani Jyoti , Mohanty Kishore K.
Published: February 2011

Finding new sources of energy and curbing global warming are two of the most important current problems. CO2 can be injected into methane-hydrate reservoirs to produce methane and sequester CO2 simultaneously. CO2 replaces methane in the clathrate cages producing methane. The goal of this work is to develop a compositional, thermal, and kinetic simulator to design and interpret lab and field scale CO2 flooding experiments of methane-hydrate in porous media. Five components (water, methane, CO2, CH4-hydrate, CO2-hydrate) and six phases (aqueous, gas, liquid CO2-rich phase, CO2-hydrate, CH4-hydrate and ice) are considered. The equations are spatially discretized with a finite volume difference method and are solved with a Newton-Raphson method in a fully implicit manner. Primary variable switch method (PVSM) is used to track the phase transitions. 1-D core scale simulations shows that the energy produced from CO2-hydrate formation is utilized for methane-hydrate dissociation. The methane-hydrate dissociation front moves at a slow rate of approximately 1/40 cm/hr for the kinetics assumed in the base case. High mole fractions of CO2 lead to CO2-hydrate formation and methane-hydrate dissociation. To dissociate methane-hydrate by CO2 injection, either we need to keep the CO2 mole fraction very high in the fluid phase or operate at a relatively lower pressure (shallower reservoirs of methane-hydrates).
Stand Investigations of ESP's and Gas Separator's Characteristics on GasLiquid Mixtures with Different Values of Free-Gas Volume, Intake Pressure, Foaminess and Viscosity of Liquid
Authors: Drozdov A. N.
Published: February 2011

The investigations of different factors influence on ESP's and gas separator's characteristics have been developed on the special laboratory stand while gas-liquid mixtures delivering. Used model mixtures ("water-gas", "water-surfactant-gas", "industrial oil-gas") good corresponded to real well's mixtures according to the gas influence on ESP operation.

The tests showed that the free-gas content, intake pressure, gas phase degree of dispersion, foaminess, viscosity of the fluid and operation regimes are the main factors which define the degree of free-gas influence on centrifugal pump characteristic. The increase of foaminess and intake pressure leads to significant lowering of negative free-gas influence on ESP operation because of the mixture's stability rise and the difficulty of gas bubbles coalescence in large cavities.

The different principle fundamentals of multistage ESP's operation are estimated for low and high foaminess gas-liquid mixtures in the artificial gas cavitations regimes. The dimensionless parameter - superficial pumping capacity factor is suggested. It permits to generalize ESP's operation cases on high foaming model and real oil-gas-water well's mixtures. These results essentially supplement and define more precisely correlations of J.L. Turpin.

The early unknown fact of lowering efficiency of centrifugal gas separator for ESP was revealed by experiments on high foaming fine dispersed gas-liquid mixtures while intake pressure increase and invariable values of free-gas intake content and liquid flow rate.

The obtained results have significant practical importance not only for increasing efficiency of well's operation by ESP, but for creating pumping oil-gas-water mixtures devices in field pipelines, and also for developing pump-ejecting systems for delivering water-gas mixtures into the reservoir in order to enhance oil recovery by SWAG process too.
Foam Assisted Gas Oil Gravity Drainage in Naturally-Fractured Reservoirs
Authors: Farajzadeh R. , Wassing B. , Boerrigter P.
Published: February 2011

This paper introduces a novel enhanced-oil-recovery concept for naturally-fractured reservoirs. We use foam to create a viscous pressure drop along the fracture that is directly transferred to the oil-bearing matrix and accelerates the oil production. We developed an expression that predicts the maximum oil rate depending on the injected gas rate and properties of the foam generated in the fracture. The results of the numerical simulation are in good agreement with the developed model.
Running Casing Drilling Bit in Extreme-Lean-Profile Wells: A Possibility that Becomes Reality
Authors: Brancato Calogero , Etorki Zuhir , Monaci Ezio , Aliko Enis , Fabre Jason
Published: February 2011

A major oil company drilled an offshore well in Libya where extreme-lean-profile (X-LP) casing was programmed. The X- LP well, a further development of the lean-profile, requires casing strings to be run in openhole sections with very little clearance between the borehole wall and the casing or liner. These include 16-in. casing through 17 1/2-in. open hole, 13 3/8- in. casing through 14 3/4-in. open hole, 11 3/4-in. casing through 12 7/8-in. open hole, and finally, 9 5/8-in. liner through 10 5/8-in. open hole.

This well was programmed and drilled using the X-LP concept with vertical sections to solve particular drilling problems while minimizing drilling costs. It was also drilled using an automated vertical drilling system and managed pressure drilling (MPD) technique in some sections because of the difficulty to drill these formations. The major difficulty consisted in drilling a very thick shale section, where formation is highly unstable with a high tendency to swell and slough and with several fractures that worsen the scenario. This formation also contains some gas that can produce a kick if not controlled with MPD techniques while drilling. Other drilling hazards included thief zones where mud losses occurred.

Because of these difficulties and because of the very tight clearance between liner and borehole wall, running the liner to bottom and properly isolating these formations was a real challenge and could determine that fine line between the success or the failure of the well. For this reason, the operator and the bit manufacturer selected to run the liner with a casing drilling bit (CDB) instead of a reamer shoe. The operator believed a standard aluminum reamer shoe would have failed to reach the bottom. Two liner strings were run with the specially designed CDB, which is made of real PDC cutters and a special steel alloy body very similar to that of a PDC bit, is more robust, and drills more effectively than a reamer shoe. These runs enabled the operator to run and set the liner strings through sections of unstable swelling shales, using the CDB to do hard reaming of long sections. The 9 5/8-in. liner string was set higher than openhole total depth (TD) because the hole was filled with cavings and the liner reached its torque limit. The 7-in. liner string was reamed down to setting depth.

This paper describes the application of these specially designed CDBs in the X-LP well, using MPD techniques, which enabled the operator to run and set liners through very difficult formations with very tight borehole/casing clearances.
Public Perception of the Oil and Gas Industry: The Good, the Bad, and the Ugly
Authors: Theodori Gene L. , Jackson-Smith Douglas
Published: February 2011

Data collected in a general population survey from a random sample of individuals in Tarrant County, Texas, were used to empirically explore issues associated with public perception of the natural gas industry. In addition, the association of public perception of the energy industry with dependent measures such as individual-level actions that (a) may or may not have been taken and/or (b) may or may not be taken in response to the exploration and production of natural gas was investigated. Echoing findings from research in two neighboring Barnett Shale counties (Theodori 2009), it appears that members of the general public in Tarrant County distrust the intrusion of the gas industry and dislike certain potentially problematic social and/or environmental issues perceived to accompany development. Conversely, these same Tarrant County residents appreciate and view less negatively the economic and/or service-related benefits that tend to result from such development. Furthermore, the results of this study suggest that the social/environmental perceptual variable is a key factor to explaining past behaviors and predicting future behaviors taken in response to the exploration and production of natural gas. Possible implications of these findings for the energy industry are proposed.
The Recommended Practice for Surface Casing Vent Flow and Gas Migration Intervention
Authors: Slater Harold J.
Published: February 2011

The migration of gas to surface by means of the production casing/openhole and the production/surface casing annulus is a common occurrence in the petroleum industry. There are also situations wherein migrating gases will negotiate a route to surface outside the surface casing.

The repair of these situations is a non-revenue generating exercise with the potential to reach significant expenditures. The recommended strategy will efficiently initiate and direct this process consequently minimizing the total cost of this intervention. The process commences with a logical technical approach to identify the gas source or sources that are responsible for the problem. The next step is to communicate with this gas source in a manner that enhances a remedial cementing activity. It concludes with the task of cement squeezing the source using a low rate cement squeeze technique to permanently seal the gas source thus preventing gas flow. This methodology has proven to be extremely successful and the subject paper describes in detail the recommended methods for identification, access to and sealing of the gas source responsible for these issues. Case histories will also be presented to illustrate strategies within the intervention.
Performance of Borate-Crosslinked Fracturing Fluid Compromised by Shear-Induced Phase Separation
Authors: Hodge Richard M. , Cawiezel Kay E.
Published: February 2011

Shear history simulation has been a useful laboratory tool to determine the effect of tubing/casing shear on the rheology of fracturing fluids. High shear rates experienced in the wellbore can significantly impair the viscosity development of metallic crosslinked fluids. The effect of shear history on the performance of metallic crosslinked fluids has been demonstrated in past studies and led to the development of many of the delayed crosslinking fluids used today. Recently, more fracturing treatments are being performed at higher wellbore shear rates and more treatments are being conducted with delayed-crosslinking borate fluids. The borate-crosslinked fluids are generally thought to be more tolerant to shear history with the crosslinking able to "re-heal" following exposure to high shear rates. Therefore, shear history simulation is rarely, if ever, conducted during rheological evaluation of borate-crosslinked fluids.

This paper examines the effect of shear history on the viscosity development of a borate-crosslinked fracturing fluid. The testing was initiated due to a series of "screen-outs" experienced with a common, delayed-crosslinking borate fluid. Testing indicated that the fluid formulation used in these treatments was not stable after exposure to the high shear experienced in the wellbore. The fluid exhibited characteristics of shear-induced phase separation resulting in significant viscosity degradation and excessive "rehealing" time. To address this problem, the fluid composition was carefully optimized to eliminate the shear-induced phase separation and accelerate viscosity development after the shear history simulation. The recommended fluid changes were implemented and resulted in successful treatments with no screen-out issues.

This paper details the testing used to observe the shear-induced phase separation and recommendations for optimizing borate crosslinked fluids used in high shear environments.
Improve Heavy Oil Recovery by Separated-Zones Horizontal Well Steam Stimulation
Authors: Zhong Liguo , Zhang Shoujun , Wu Fei , Lang Baoshan , Liu Heng , Liu Tao , Liu ShuXia , Gao Wenlong
Published: February 2011

Horizontal well steam injection is effective to recover heavy oil for its large reservoir contact. To date, more than 150 horizontal wells have been drilled in Shuguang oil region, most of them are operated in steam stimulation and SAGD processes, and completed with slotted liner at length from 100 m to 500 m. But it is much challenging to recover oil from reservoir along horizontal well proportionally because of steam characteristics, large well length and reservoir heterogeneity. Results of simulation and field temperature testing show that only about half of reservoir along horizontal wellbore is recovered well, and average OSR (defined as ratio of oil production to steam injection) is less than 0.28, and it is not satisfying for the large cost of horizontal well drilling and completion. Furthermore, steam crossflow between wells and pressure depletion in local reservoir well steamed could also result in reduction in oil production and OSR.

To improve horizontal well steam injection, separated-zones horizontal well steam stimulation technology is developed, in which temperature sensitive packers, outlets, pressure sensitive valves and ball sealers are involved. The steam injection of different zones separated by packer(s) could be regulated or controlled according to engineering design. There are four techniques developed including dual-zones steam injection in sequence or at one time, selected zone steam injection, and simultaneous multizones steam injection. In order to investigate temperature and steam injection of different reservoir zones along horizontal well in different steam stimulation process, experiment, numerical simulation and field testing are carried out in past three years. In this work, laboratory experiments are carried out with large simulation apparatus packed with sampled oil sand and equipped with temperature sensors and pressure sensors at first. Secondly, structure of steam injection pipes and steam injection scheme are optimized based on numerical simulation, and primarily reservoir selection requirements are also provided. Thirdly, result of application of separated-zones steam injection to 76 wells and monitoring of temperature and pressure is presented, and considerable improvement of steam injection and heavy oil recovery obtained. At last, the future of intelligent separated-zones horizontal well steam injection is prospected.