bluuebunny/crossref_metadata_2025_split huggingface dataset:
Parameterization Techniques to Improve Mass Conservation and Data Assimilation for Ensemble Kalman Filter
Authors: Chen Yan , Oliver Dean S. 
Published: July 2010

Abstract
The ensemble Kalman filter (EnKF) is an attractive method for assisted or automatic history matching. In particular, it has been shown to be possible to efficiently match many types of data by adjusting many types of reservoir model variables, including gridblock permeabilities and porosities, facies locations, relative permeability curves, fault transmissibilities, and initial fluid contacts. At each analysis step of EnKF, model and state variables are updated to honor the production history and prior knowledge of the reservoir description using a correction that is constructed from a linear combination of the forward models. Because the update in the ensemble Kalman filter is linear and variables may be adjusted beyond their plausible range in which case the updated values are sometimes truncated, mass conservation may be violated in the updated models.
Proper selection of the model and state variables to be updated in EnKF is critically important for achieving good data match, retaining geological realism of the updated ensemble and satisfying nonlinear constraints that may apply. In this paper, we discuss parameterization techniques for these three different purposes. We revisit the updating formulation of EnKF and investigate the constraint on the weighting coefficients at the analysis step. We show that by reparameterization of the state vector, nonlinear constraints such as conservation of mass or volume, can be satisfied without complicating the updating process. The ensemble approximation of the covariance tends to be strongly corrupted by noise when the true correlation is small. Localization can regularize the ensemble-based estimate and reduce the detrimental effects of the spurious correlation, but also eliminate the effect of true correlations whose magnitude in individual gridblocks is small, but whose cumulative effect may be large. Appropriate parameterization in addition to localization could better constrain the solution of the inverse problem. Finally, the choice of model variables may also depend on observations that are available. Including model variables that are highly sensitive to certain types of data provides improved data match and more realistic updates.
A large scale reservoir model is used to illustrate these parameterization techniques. By using these techniques multiple realistic history matched models were obtained that provide reliable basis for accessing uncertainty and for design of reservoir management strategy.
Production Logging Case Studies: What Can We Say about the Well, in Addition to the down Hole Flow-profile?
Authors: Eissa Moustafa , Joshi Sameer , AlTajar Firas , Sobeih Mohamed , Alhussini Osama , Alsafadi Ghassan 
Published: July 2010

AbstractHistorically the main reason for running production logs (PLT) is to obtain the down hole flow profile, which is needed either for reservoir monitoring or to decide the proper remedial action in production wells.This emphasis on calculating the down hole flow profile with the spinner & hold up tools tends to reduce the focus on the interpretation of the other production logging sensors that are normally recorded in the production logging string (such as Gamma Ray, Pressure, and Temperature). Therefore the authors would like to stress in this paper on the importance of these additional sensors and how much extra information can be obtained through the proper interpretation of these sensors.In this paper we present seven cases that address the importance of interpreting the other sensors:➢Case # 1: Gamma Ray (GR) interpretation that helped to detect the presence of radioactive material in the hydrocarbon and understand the relation between the chemical diverters that were used during acid stimulation and the accumulation of the radioactive materials in the well bore during the shut-in conditions➢Case # 2: Qualitative interpretation of the spinner data response can help to understand the presence/nature of solids and/or viscous fluid and its relation to the performance of unproductive perforations➢Case # 3: Down hole fluid density that was computed from pressure data was used to detect the source of potential surface water production. This helped to design a successful water shut-off job that was performed later.➢Case # 4: Using pressure data to get the pressure, permeability, and skin in multi layer wells➢Case # 5: Caliper comparison to confirm the impact of acid stimulation on borehole shape.➢Case # 6: Gas Hold up and pressure measurements were used to verify the oil bubble point pressure value.➢Case # 7: Comparison of pressure measurements between surveys to understand horizontal well production profile behaviorBased on this work we would like to introduce an integrated/practical workflow for production logging interpretation that honors data from all the acquired sensors.
Research Progress of Modelling on Cold Heavy Oil Production with Sand
Authors: Pan Yi , Chen Zhangxin , Sun Jian , Bao Xia , Xiao Lizhi , Wang Ruihe 
Published: July 2010

Abstract
Heavy oil has been playing a critical role in today's world energy supply. The total amount of heavy oil in place is five to ten times greater than that of the current proven conventional crude. One of the recovery methods, which produces both oil and unconsolidated sands, is known as Cold Heavy Oil Production with Sand (CHOPS). The advantages of CHOPS lie in its commercial success as an inexpensive start up application for heavy oil reservoirs as well as its considerable recovery rates. The general reservoir characteristics associated with successful applications of CHOPS have been established, particularly highlighted in thin reservoirs with non-active edge and bottom water. Heavy oil researchers have accumulated local knowledge for the CHOPS fields; particularly, research groups in Alberta have taken integrated approaches to the questions posed by the field success of cold production. CHOPS gives high early production rates and becomes very efficient in the thin reservoirs where some thermal methods have been economically unsuccessful.
Aggressive sand production was encountered in California prior to the First World War. Two key mechanisms lead to the success of cold production in laboratory and field studies: foamy oil flow and wormhole network growth. A variety of numerical models are presented and compared in this paper. Such models can be mainly divided into two broad categories: preliminary model and comprehensive model. With a large number of variables still in limited recognition for the complex mechanisms, several models lack capability in fully simulating CHOPS processes, while progress was achieved in modeling the reservoir heterogeneity with the integration of seismic attributes at specific fields. A detailed discussion of the strengths and weaknesses of cold production models is proposed. The paper ends with the future work of modeling proposed on cold production.
Chemical Treatment to Mitigate Condensate and Water Blocking in Gas Wells in Carbonate Reservoirs
Authors: Ahmadi M. , Sharma M. M. , Pope G. A. , Torres D. E. , McCulley C. A. , Linnemeyer H. 
Published: July 2010

Abstract
Many gas wells suffer a loss in productivity due to liquid accumulation in the near wellbore region. Chemical stimulation may be used as a remedy, by altering the wettability to non-liquid wetting. Successful treatments decrease liquid trapping, increase fluids mobility, and improve the well&#x92;s deliverability. This paper presents the first effective chemical treatment to mitigate liquid blocking in carbonate gas reservoirs. Screening tests were developed to quickly and effectively identify suitable chemicals from a large pool of compounds. X-ray Photoelectron Spectroscopy (XPS) measurements and drop imbibition tests with water and n-decane were found to be necessary but not sufficient indicators of the effectiveness of the chemicals and were used as screening tests.
An integral part of the development of the treatment solution was the selection of a solvent mixture capable of delivering the fluorinated chemical to the rock surface. The treatment solution, mixture of chemical dissolved in solvent, must be stable in the presence of both brine and condensate so that it will not precipitate and will not reduce permeability of the rock. We demonstrate measured relative permeability values in Texas Cream limestone cores (TCL) from high-pressure, high-temperature (HPHT) coreflood experiments before and after treatment. Measurements were made using a pseudo-steady-state method with a synthetic gas-condensate mixture. To enhance the durability of the treatment a special amine primer is introduced. The gas relative permeability increased considerably, about 80%, after the treatment compared to that before treatment. This increase remained substantial, greater than 60% after injection of more then 1000 pore volumes (PV) of gas-condensate mixture. We found an even greater increase in gas relative permeability during unsteady displacement of water by methane. The improvement remained after injecting 20 PVs of brine and increasing the temperature in the treated core from 175 °F to 275 °F.
The chemical treatment developed in this research can be applied to increase well deliverability and final recovery of both gas and condensate in the field, providing that it is properly designed by considering key parameters such as reservoir pressure and temperature, brine salinity, and initial water saturation.
Alaskan Heavy Oil: First CHOPS at a Vast, Untapped Arctic Resource
Authors: Young J. P. , Mathews W. L. , Hulm E. J. 
Published: July 2010

Abstract
Alaska&#x92;s North Slope is a world-class petroleum resource basin with two of the largest producing fields in North America, Prudhoe Bay and Kuparuk River Unit. What is not widely known is the vast resource of heavy oil above these reservoirs. Although comparable in size to these fields, it remains untapped due to the complexity of producing heavy oil in an arctic environment. The keys to commercializing this heavy oil resource are primarily technology and favorable economics. This paper is focused solely on the technology hurdles.
Development of heavy oil in the Arctic represents a significant departure from conventional oil developments on the North Slope as well as established heavy oil developments elsewhere in the world. The combination of low well rates, high costs, and arctic conditions require a sustained commitment to developing new approaches for unlocking the resource. To progress this opportunity BP initiated an appraisal program involving resource characterization, production pilots, and development screening. This paper describes early appraisal results from a cold heavy oil production with sand (CHOPS) flowback and multi-zone drill-stem testing to obtain quality reservoir fluid samples.
Simulation of Time-lapse Mineral Carbonation and Isotope Fractionation of Injected CO2 in Aquifer: Implications for Monitoring CO2 Sequestration
Authors: Jung W. , Yang D. 
Published: July 2010

Abstract
A theoretical aquifer model predicts time-lapse mineral carbonation and isotope fractionation of injected CO2 in sediment. Geologic sequestration of CO2 has become one of the promising ways to reduce atmospheric emission of CO2 from human activity. However, the current and future effects of geologic storage after injecting CO2 are not known well. We developed a simple mathematical model based on a transport-reaction equation and calculated the abundance of carbon stable isotope in the reservoir with respect to time which allows us to predict CO2 saturation in sediment or CO2 flume distribution by ground reservoir water. These results indicate significant potential of the theoretical aquifer model for monitoring and verification of CO2 sequestration into the sediment.
Density of High Pressure and Temperature Gas Reservoirs: Effect of Non-hydrocarbon Contaminants on Density of Natural Gas Mixtures
Authors: Tabasinejad F. , Moore R. G. , Mehta S. A. , Van Fraassen K. C. , Barzin Y. , Rushing J. A. , Newsham K. E. 
Published: July 2010

Abstract
New experimental density data are generated in this study for light and heavy dry gas mixtures. The light mixtures consist mostly of methane and small fractions of ethane, propane, and nitrogen. Normal alkanes up to C6, iso-butane and iso-pentane together with carbon dioxide form the heavier gas mixtures. For each mixture, isothermal gas density is measured from 3.45 MPa to 140 MPa at temperatures of 423.15 K and 478.15 K. Effects of CO2 and N2 as two non-hydrocarbon contaminants, on density of gas mixtures are examined in steps of 5 mol%, 10 mol%, and 20 mol%. In addition, water vapor influence on gas phase density of water-saturated gas mixtures is also investigated. Different correlations for sweet and sour gas critical properties are combined with the most widely used equations of state (Hall-Yarborough and Dranchuk-Abou-Kassem) to predict density data for comparison with 450 experimental measurements. The most important results demonstrated from this study are:
Among all correlations, the combination of the Hall-Yarborough equation with the pseudo-critical properties correlated by Sutton generates the lowest average absolute deviation (AAD) between predicted and experimental density data. The correction term developed by Wichert and Aziz to modify the pseudo-critical properties due to the presence of non-hydrocarbon compounds in the gas mixture, drastically improves the prediction of density data. At very high pressure and temperature conditions, effect of water vapor becomes more significant on gas phase density and it should be considered in density related correlations.
Development and Field Pilot Test of a Novel Viscoelastic Anionic-Surfactant (VAS) Fracturing Fluid
Authors: Zhang Jin , Zhang Mei , Zhang Shicheng , Bai Baojun , Gao Zhen 
Published: July 2010

AbstractA novel fracturing fluid called VAS (anionic surfactant type) has been successfully developed and applied in both oil and gas wells in China. VAS can not only minimize matrix damage caused by modifying the rock surface charge and lowering watersensitive and water-lock. This paper presents the stimulation mechanisms of the novel VAS fracturing fluid. Field demonstrations indicate that, for the wells using the VAS fracturing fluid, the production increased remarkably and stabilized longer than the wells using water-based Guar gum fracturing fluid. Averagely, the production for the wells using this VAS fracturing fluid increased by 120% compared with the wells using acidic fracturing fluid and increased by 89% compared with the wells using ethyloic fracturing fluid.
A New Model for Predicting Inflow Performance of Fractured Horizontal Wells
Authors: Yuan Hong , Zhou Desheng 
Published: July 2010

Abstract
Based on the analysis of horizontal well flow and flow characteristics in fractures, this paper presents a new method to predict the inflow performance of fractured horizontal wells with single phase flow at steady state conditions.
More and more horizontal wells are drilled today and we encounter more fractured horizontal wells. While predicting the inflow performance of fractured horizontal wells, we found that there is a need for a new model which couples the flow from rock matrix and flow from fractures, and is applicable for horizontal wells both with and without fractures. The model presented in this paper serves the purpose.
The presented model can be easily used in horizontal wells with or without fractures. Results from the new model are compared with those from commonly used models in petroleum industry for fractured and unfractured horizontal well flow models such as Economides et al., Joshi, Babu and Odeh, and Guo and Schechter. Results from the new model are also compared with field data obtained from published literature.
The new model may be used in well planning, production design, production system analysis and well efficiency improvement.
Storage and Output Flow From Shale and Tight Gas Reservoirs
Authors: Rahmanian Mohammad , Solano Nisael , Aguilera Roberto 
Published: July 2010

Abstract
Crossplots of porosity vs. permeability from various North American basins show that there is a continuum between conventional, tight and shale gas reservoirs. This is significant as some of the key issues, particularly in shale and tight gas reservoirs, are having good estimates of storage and flow capacity. The crossplots include data from the Fayettville, Barnett, Ohio and Marcellus shales in the United States; Horn River and soft shales in Canada, tight gas Nikanassin formation in Canada and several conventional North American gas reservoirs. The data used in the crossplots have been obtained from plugs, crushed samples and drill cuttings.
The results permit integration of the storage and potential gas deliverability for determining flow units and other important characteristics such as brittleness and/or ductility, hydraulic fracturing alternatives, effect of water saturation and mud filtrate; and differentiation between viscous and diffusion dominated flow. Examples of simulation at the pore throat level, from which it is possible to estimate petrophysical, rock-fluid interaction and rock mechanics properties, are presented.
The storage and flow capacity in the case of stacked layers, or lateral variations of conventional, tight and shale gas formations, are discussed in detail. The data suggest that permeability determinations from crushed shale samples might be pessimistic as they do not take into account the possible presence of microfractures and pores in organic matter within shale matrix.
It is concluded that crossplots of porosity vs. permeability are very powerful for distinguishing and evaluating storage and flow capacities of conventional, tight and shale gas reservoirs. The concept of flow units in shales and tight gas, and its differentiation from conventional formations, should prove powerful in future simulation work.
Permeability Estimate for the South Ellwood Fault
Authors: Boles J. , Horner S. , Garven G. 
Published: July 2010

Abstract
Fault-zone permeability kf has been estimated for an offshore well in close proximity to the South Ellwood fault at Platform Holly, Santa Barbara channel, California. This fault runs parallel to the axis of the structure of the South Ellwood field, which produces from the Monterey Formation that has a mean permeability of about kf ~ 10 md about 1 km (3000 ft) beneath the sea floor. The pressure has been 77% of hydrostatic since 1984. Tidal frequency pressure variation from a shut-in well (Well #13) completed close to the fault, indicates the reservoir is in local communication with the sea bed via the fault zone.
Our permeability estimate comes from Well #7, completed about 5.2 km (3.2 miles) southeast of Well #13. Steel tents that overlie Well #7 on the sea bed capture gas seeping from the damage zone of the South Ellwood fault. When Well #7 is shut down, seepage production increases by about 1.0 Mm3/D (35 Mcf/D) to 1.6 Mm3/D (60 Mcf/D) over shut down periods ranging from 21 days in 2003 to 45 days in 2005, respectively. Using these changes in flow rate and the pressure differences between the seep tents and the perforation intervals in the well, we have calculated kf = ~30 md with respect to gas for the approximate 1 km (3000 feet) long fracture/fault flow path with an average cross section of 1860 m2 (2.0 × 104 ft2), based on Darcy's equation. Our fault-zone permeability estimate indicates that the damage zone of a fault can have a relatively high kf vertical value over a kilometer scale.
Simplified Yet Rigorous Forecasting of Tight/Shale Gas Production in Linear Flow
Authors: Nobakht M. , Mattar L. , Moghadam S. , Anderson D. M. 
Published: July 2010

Abstract
This paper presents a simplified, yet rigorous, method of production forecasting for tight/shale gas reservoirs exhibiting extended periods of linear flow, without the use of complex tools. The method is simple as it relies principally on a plot of inverse rate versus square root time, and it is rigorous in that it is based on the theory of linear flow and combines the linear flow transient period with hyperbolic decline during boundary-dominated flow.
The dominant flow regime observed in most fractured tight/shale gas wells is linear flow, which may continue for several years. This linear flow will be followed by boundary-dominated flow at later times. Therefore, the method proposed in this study is applicable for forecasting production data for these wells, as it considers these two important flow regimes.
The method is validated by comparing its results against test cases which are built using numerical simulation. For each case, only the first year of the synthetic production data is then used for the analysis. It is found that there is excellent agreement between the forecast rates obtained using this method and the numerically simulated rates.
Currently, analysis techniques using material balance time are being used in industry to analyze shale/tight gas reservoirs. Because material balance time is actually boundary-dominated flow superposition time, these analyses may show symptoms of boundary-dominated flow even though the reservoir is still in transient flow. Here are the advantages of the forecasting method proposed in this study: (1) It is not biased towards any flow regimes, as no superposition time functions are used; (2) Reliable forecasts can be obtained without using pseudo-time-this is an advantage, as using pseudo-time introduces complexities and an iterative procedure; and (3) The only externally specified parameter required is the drainage area.
Integrated Risk Analysis Criteria for Managing Exploration and Development of Oil and Gas Assets
Authors: Belhaj Hadi , Haroun Mohamad , Lay Terry 
Published: July 2010

Abstract
Current petroleum industry practice (as reported by Beucher et. al.1 and Bratvold and Begg2 etc. AAPG 2008) adopts schemes that aim at separating risk into two main categories; subsurface risk that includes resource size, production rate, and access cost and surface risk that demonstrates total expenditure, facilities delivery, delays, performance, oil/gas revenues and costs.
A recent SPE review (Bartvold el al SPE RE 2009) of decision making in the petroleum industry shows great dependence on VOI (Value of Information), to manage risk. VOI cannot stand alone as a decision making tool. There are also shortcomings in the use of Monte Carlo simulation.
In this paper, we introduce an integrated approach for handling risk associated with oil and gas exploration as well as development of mature reservoirs through EOR and IOR. Test case includes a major asset in the Arabian Gulf Region selected due to its varying reservoir settings.
The proposed approach basically, integrates uncertainty elements that may create "business risk" causing "business impact". This solution methodology breaks down each risk parameter to sub-parameters. Critical and non critical sub-parameters are broken down to even more detailed pieces of risk components, down to the smallest fragments of risk. Thereafter, a down-to-top risk analysis technique is adopted to reach to target NCF (Net Cash Flow).
Proposed is a tool for risk analysis modeling criteria related to exploration of oil and gas, and development of mature fields. In particular, it focuses on comprehension and inclusion and negates lumping/dropping of any risk parameter. This is not only because petroleum industry is surrounded by lots of uncertainties and therefore carries a huge risk, but also because other economies are revolving and highly dependent on this industry. In many cases, ignored risk parameters, that once thought non-critical, turned to business disasters.