bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Dynamic Model for High-Rate Acid Stimulation of Very Long Horizontal Wells
Authors: Mogensen Kristian , Hansen Jens Henrik 
Published: December 2007

Abstract
In 1999, Mærsk Olie og Gas AS introduced the Controlled Acid Jet (CAJ) completion and stimulation technique and over the last 7 years more than 300 km of reservoir sections have been implemented mainly in the Danish chalk fields (see SPE paper 78318 for a description of the concept). This method allows cost effective single operation acid stimulation of ultra long horizontal wells (15,000+ ft) in carbonate reservoirs. Successful implementation of the CAJ technique requires numerical modelling of the dynamics of the entire stimulation process to ensure equal distribution of the acid, effective control of the wormhole growth rate in all sections of the well, displacement of mud along the entire reservoir section, handling of significant (1,000+ psi) formation pressure gradients along the reservoir section etc. Especially the analysis of the mud displacement process along the horizontal sections has proven to be critical for optimising the completion design.
The key to the successful field developments has been the gradual improvement of the CAJ technique which has been achieved by modelling the effect of a range of parameters prior to the full field trial to optimise the design of the completions.
This paper describes the building blocks of the newly developed modelling algorithm* that captures the physics of the stimulation process and the numerical solution methods required to apply the CAJ technique in ultra long horizontal wells.
The model has been matched to actual stimulation data and modelling is now widely used resulting in more effective stimulation and an extensive application of the CAJ technique for the development of marginal fields.
Characterization of a Reef Reservoir Permeability Using Well and Seismic Data
Authors: Hu Guangyi , Huang Xuri , Mei Minxiang , Gu Li , Xiao Chaozheng 
Published: December 2007

Abstract
This study is based on a field development planning study of a reef reservoir with only one well and 3D seismic data. The reef has porosity of inter-grain, organically-derived pores and depositional or structural fractures. A high degree of heterogeneity of the reef reservoir makes the characterization more difficult. This work implemented an approach starting with core description, and deposition-driven interpretation, inversion and forward modeling of seismic data. Subsequently, pore structures, fractures and facies are identified using core description and logs. Fracture density is obtained from the core description for each facies. Porosity and permeability are statistically related using the core data according to the facies in the core. The matrix permeability field is generated in three dimensions based on porosity from the seismic. The fracture permeability is found to correlate with the matrix porosity from an adjacent reef field. However, due to the complexity of the fracturing in the reef, the core description needs to be corrected using the well test data and an analytical model of cracks, such that the core-described fracture can be equivalent to well test-detectable fractures. The fracture permeability is added to the matrix permeability according to the facies. Based on the different possible depositional models, the uncertainty is analyzed through the corresponding seismic inversions, and derived facies.
Successful Application of Chemical Injection Rate Control Valves
Authors: Duhon H. J. , Annadorai K. M. 
Published: December 2007

Abstract
This paper presents an overview of a systems approach to the design and troubleshooting of IRCVs (Injection Rate Control Valves) used in deepwater chemical injection systems. The inherent problems associated with these simple flow regulators stem largely from the failure of design engineers to take a systems view in design. Along with the application of lessons learned from previous IRCV system failures, this systems approach provides a design method which will allow users to avoid many of the pitfalls inherent in design, installation, testing, commissioning and operation of IRCV systems.
Multicomponent Sorption Modeling in ECBM Displacement Calculations
Authors: Jessen Kristian , Lin Wenjuan , Kovscek Anthony R. 
Published: December 2007

Abstract
Enhanced coalbed methane (ECBM) recovery by injection of CO2 or by injection of mixtures of CO2 and N2 is an attractive method to recover additional natural gas resources while at the same time sequestering CO2 in the subsurface. The dynamics of ECBM recovery processes are determined in large part by the sorption behavior of mixtures of CH4, CO2 and N2 on the coal surface. Conventional simulation tools use the extended Langmuir model for predicting the sorption behavior of the gas mixtures that form during a displacement process. In previous work, we demonstrated the applicability of this approach for binary CH4/CO2 and CH4/N2 displacements by comparison to lab-scale experiments. The extended Langmuir model was, however, unable to describe the behavior of ternary CH4/CO2/N2 displacements. Adsorption hysteresis is a complicating factor also. This paper investigates the accuracy of ternary gas displacement calculations. We find that a sorption model more sophisticated than the extended Langmuir model is needed to represent the dynamics of multicomponent systems. We use the Ideal Adsorbate Solution model (IAS) and compare the predicted behavior to standard calculations and experimental results.
Initially, we describe the implementation of the IAS model into our dual-porosity simulator. The IAS model requires an iterative scheme as opposed to the explicit calculation from the extended Langmuir model. Accordingly, the IAS model is more computationally expensive than traditional approaches. The predicted displacement behavior substantially agrees with the experimental observations in comparison to the inaccurate predictions from the traditional approach for a series of ternary CH4/CO2/N2 displacements.
Accurate tools for prediction of displacement performance in ECBM processes are instrumental in design and implementation of enhanced gas recovery schemes. The results and analysis presented in this paper, demonstrate that more sophisticated thermodynamic models must be used in ECBM simulators when mixtures of CO2 and N2 are used to displace CH4 from coalbeds.
Analytical and Numerical Investigation of Multicomponent Multiphase WAG Displacements
Authors: LaForce Tara , Jessen Kristian 
Published: December 2007

Abstract
In this paper we study the ability of analytical solutions for four-component three-phase flow to predict displacement efficiency in water alternating gas (WAG) injection processes. We present equivalent analytical solutions for Riemann problems with injection compositions that are the average water and gas mixture for various WAG injection schemes. These solutions are compared to numerical calculations with variable slug sizes and used to explore the effect of slug size, injecting water versus gas first, and the average injection composition on displacement efficiency in compositional WAG schemes.
We model immiscible WAG injection of water and CO2 into an oil reservoir containing C10 and CH4 with and without a mobile aqueous phase present initially. These are the first analytical solutions for three-phase initial conditions in quaternary systems. The magnitude of the oil bank and the breakthrough time of the injected fluids are accurately predicted by the analytical solutions, even for displacements where large water and gas slugs are injected. As slug size decreases, the displacements predicted by numerical calculations converge to the analytical solutions.
The sequence of shocks in composition predicted by the analytical solutions is observed in WAG injection simulations for relatively large slugs, regardless of the injection sequence. The WAG simulations appear as if oscillations in the profiles are super-imposed on top of the sequence of rarefaction and shock waves predicted by analytical solutions. The trailing end of the water and gas profiles are sensitive to whether water or gas is injected first. However, the injection sequence and slug size has little impact on the bank of heavy hydrocarbon, even at the trailing end of the displacement.
An Investigation Into the Need of a Dynamic Coupled Well-Reservoir Simulator
Authors: Nennie E. D. , Alberts G. J. N. , Belfroid S. P. C. , Peters E. , Joosten G. J. P. 
Published: December 2007

Abstract
Within the research framework of the "Integrated System Approach Petroleum Production" (ISAPP) knowledge center of TNO, TU Delft and Shell, the necessity of taking the interaction between dynamic reservoir and dynamic well behavior into account when optimizing a producing asset is investigated. To simulate dynamic phenomena in the well and in the reservoir, a dynamic multiphase well simulation tool (OLGA) and a dynamic multiphase reservoir simulator (MoReS) have been used. Both simulators have been coupled using an explicit scheme.
The dynamic well simulator, the dynamic reservoir simulator and the coupled dynamic well-reservoir simulator have been used to simulate a realistic test case which consists of a horizontal well with three inflow sections located in a thin oil rim. A number of scenarios are investigated that play a crucial role during different stages of the well's lifetime: naturally occurring phenomena, e.g. coning, and production dynamics, e.g. shut-in.
The results of dynamic well simulations, dynamic reservoir simulations and coupled well-reservoir simulations are presented and an overview is given of the cases where the results of the coupled simulations are significantly more accurate in comparison to stand-alone well or reservoir simulations. For gas coning it is shown that the coupled simulator has much faster pressure transients after gas breakthrough than the dynamic reservoir simulator. Therefore, the coupled well-reservoir simulator should be used to simulate gas breakthrough and to optimize production using gas coning control. For small time scale phenomena, order of less then one day, the well and reservoir transients overlap. Simulations show that the coupled simulator is essential for an accurate prediction of the well-reservoir interaction during these small time scale phenomena.
Automatic Surveillance System for Large Gas Fields with Multifrequency Measurements
Authors: Mota M. , Campos O. M. , Escalona H. , Teran L. D. , Sandoval G. 
Published: December 2007

Abstract
This paper presents the results of an automatic surveillance system implemented by PEMEX for one of Mexico's largest gas fields. Activo Integral Burgos (AIB) is a typical example of large gas field where production declined due to gas-loading backpressure and reduced permeability in the target formation. The fast decline of the gas wells during their first year of production drove a change from reactive into proactive management tactic to monitor the field and to select candidates for workovers. However, the large number of wells in AIB (approximately 2000 active wells) and the fact 95% of data is manually captured made the implementation of automatic surveillance particularly challenging.
We introduced an automatic surveillance solution that synchronizes the data collected daily in more than 200 wells. Conventional production tools, including Nodal modeling, Turner's equation, Decline Curve Analysis, or Pressure Survey, were individually validated and subsequently implemented as a sequence of automated routines to process the data over the entire field. The data was then analyzed using a self-organizing-map engine to automatically identify wells where fluid loading impedes production. Daily production rates were also computed using nodal models automatically updated with operational data for each well.
The integration of tasks including production data gathering and standardization, monitoring, reporting and alarm functionality, was a key element for the successful and efficient management of gas-loading problems at the field scale. Milestones achieved with this implementation included the automatic identification of problematic wells and a reconciliation of the production rates measured at the gathering stations with rates calculated at the well level.
This surveillance methodology offers new perspectives for the proactive management of wellbore liquid-loading problems in large fields with very limited data stream. The early-stage diagnosis of problems enables the operator to make decisions in record turn-around times and extends the productive life of the wells beyond initial expectations.
PC-SAFT Equation of State Applied to Petroleum Reservoir Fluids
Authors: Pedersen Karen Schou , Sørensen Casper Hadsbjerg 
Published: December 2007

Abstract
The PC-SAFT equation has been proposed as a potential next generation equation of state in the oil industry. It has already obtained widespread use for simulations on polymer systems, which shows that it has a capability of handling phase equilibria for systems with heavy hydrocarbons. A C7+ characterization procedure for use with the PC-SAFT equation has been developed and used to test how PC-SAFT performs on various types of petroleum reservoir fluids ranging from natural gas mixtures to heavy oils with asphaltenes. Promising results are seen for asphaltene onset pressures and for oil mixtures in general. With the currently published pure component parameters PC-SAFT is inferior to cubic equations of state for simulations on gas and gas condensate mixtures.
Water Injection Optimization for a Complex Fluvial Heavy-Oil Reservoir by Integrating Geological, Seismic, and Production Data
Authors: Feng Xin , Wen Xian-Huan , Li Bo , Liu Ming , Zhou Dengen , Ye Michael Q. , Hou Dongmei , Yang Qinghong , Lan Lichuan 
Published: December 2007

Abstract
BZ25-1s field in Bohai Bay, China is characterized as a complex fluvial channelized reservoir where small meandering channels (100-300m wide and 500 - &gt;1000m long) were deposited at different geological times cross-cutting each other. There are many isolated small reservoir systems following channel distributions. Early production showed steep pressure and production decline. Quick implementation of water injection is needed to arrest the fast production decline and to stabilize reservoir pressure.
While designing the water injection plan, we faced a number of challenges, such as high mobility ratio (oil viscosity of ~200 cp), strong heterogeneity, poor reservoir connectivity, complex channel geometry, and irregular well patterns. A workflow integrating geological, well log, seismic and dynamic production data was developed to optimize water injection plan for this field.
Following the workflow, the optimal water injection design for platforms D and E areas was developed and quickly implemented within the first year of production. We started with a relatively small water injection rate and gradually increased the injection rate to avoid the fast water breakthrough and yet to limit the pressure decline rate. The responses from the water injection were very positive resulting in stable reservoir pressure and increase of oil production. Before water injection, the production decline rates were 30% and 50% for the wells in platforms D and E. After 1 year of water injection, oil production decline rates were reduced to 19% and 14%, respectively.
The responses of water injection for different well groups were analyzed in a timely fashion and adjustments to injection/production strategies were implemented accordingly. New information from the water injection response analysis was used to update the geological model to reduce the model uncertainty, as well as to adjust the water injection strategies for better sweep efficiency. Our experiences showed that such dynamic adjustment of injection and production schedule is very important to achieve better water injection efficiency for this heavy oil reservoir with complex channel geometry.
Success Stories in Onshore Production Surveillance and Optimization
Authors: Deaton David F. , Kloosterman John T. 
Published: December 2007

Abstract
This paper presents the assessment methodology, technology, data sources, workflows, critical factors and intermediate results of Marathon Oil Company's production surveillance solutions implemented within two major asset teams, Permian Basin and East Texas. It is represented as a model for operators implementing digital oilfields, i-fields, or automation to improve the surveillance aspect of their production operations. The paper presents an asset-based collaborative project process for needs assessment, a surveillance solution for linking and visualizing production data, a workflow definition process, and a mentoring approach on the solution and workflow to insure successful implementation and value realization.
Borehole Effects and Correction in OBM With Dip and Anisotropy for Triaxial Induction Tools
Authors: Wu P. , Wang H. , Minerbo G. , Homan D. , Barber T. , Frey M. 
Published: December 2007

Abstract
The latest advance in resistivity logging is the multi-spacing triaxial induction tool. In addition to the conventional induction logs, a triaxial induction tool provides added capability to measure formation anisotropy (horizontal and vertical resistivities), relative dip, and azimuthal angles over a wide range of logging conditions. The anisotropy measurement is very important in low-resistivity pay analysis, while the dip and azimuth measurements have many important geophysical and geological applications.
However, due to the physics of the triaxial induction measurements, the borehole effects are significant even for oil-base mud (OBM) conditions. These borehole effects must be corrected in order to obtain accurate measurements of the formation properties. Through extensive modeling studies, we learned that borehole effects depend on many parameters, including hole diameter, tool eccentric distance and azimuth, mud resistivity, formation horizontal and vertical resistivities, formation relative dip, and azimuth angles. Removing the borehole effects is a very difficult and complicated three dimensional (3D) electromagnetic inversion problem, which involves many free parameters.
We have developed an inversion algorithm for OBM filled boreholes that robustly solves for horizontal and vertical resistivities, relative dip and azimuth, tool eccentric distance and azimuth. The model for the inversion is an eccentric tool in a borehole through an anisotropic formation with a dip angle. These inverted parameters can then be used to derive the borehole correction for the triaxial measurements. We demonstrate the algorithm through theoretical examples and field logs. The algorithm is very efficient and fast enough to be implemented as real-time well site answer product.
Experimental Study of CO2 Injection into Saline Formations
Authors: Cinar Yildiray , Riaz Amir , Tchelepi Hamdi A. 
Published: December 2007

Abstract
We present experiments at the laboratory scale to investigate the influence of gravitational, viscous and capillary effects on the CO2 injection process. Two-dimensional experiments are performed in a vertical glass-bead pack, in the parameter range of practical flows, i.e. with Bond numbers of about 10-3, and capillary numbers of the order 10-4. Experiments are carried out primarily to demonstrate the type of flow regimes that occur under favorable as well as unfavorable conditions of density and viscosity. Experiments demonstrate the existence of pore scale instability in the presence of unfavorable gradients of viscosity and density, and as such, appear to be incapable of being modeled by conventional means. A comparison with estimates from percolation theory shows good agreement with experimental observations.
Horizontal Well Gravel Packing: Dynamic Alpha Wave Dune Height Calculation and Its Impact on Gravel Placement Job Execution
Authors: Chen Zhongming 
Published: December 2007

Abstract
Gravel packing long horizontal wells presents many challenges to completion operations. The accurate calculation of Alpha wave dune height under dynamic wellbore conditions is on the top of the list. Alpha wave dune height is critical during job planning and the afterward successful gravel placement execution. Excessive Alpha wave dune height is the cause of many early time screenout and job failures. The job parameters, including wellbore geometry, pump rate, leakoff and leakoff control, fluid density and viscosity, gravel particle size and geometry, liteProp and conventional gravel, wellbore temperature profile, bottomhole pressure distribution, will all have impact on Alpha wave height.
This paper investigates and summarizes several particle transfer models, analytical and empirical ones, their applications in Alpha wave dune height calculations, their limitations and effective application windows. The paper also provides dynamic Alpha wave height calculation methodology to account for dynamic bottomhole conditions, especially the fluid leakoff to formation and to screen wash pipe annulus, bottomhole in-situ gravel concentration, and their impact on Alpha wave dune height calculation. The sensitivities of these models under different job conditions are also studied.
Several job designs and application histories are presented in the paper to demonstrate the application of different particle transport models. Guidelines are provided for operators to make proper adjustment when an undesired condition is present during gravel placement.
Improving Well Productivity and Profitability in the Bakken—A Summary of Our Experiences Drilling, Stimulating, and Operating Horizontal Wells
Authors: Besler Monte R. , Steele John W. , Egan Tanner , Wagner Jed 
Published: December 2007

Abstract
This case study will summarize the lessons learned during the stimulation and operation of horizontal laterals completed in the Middle Bakken formation of North Dakota and Montana. This paper will compare the production histories of these wells to offset wells completed with other techniques to evaluate best industry practices. Insight will be shared as to the effect of lateral length, wellbore azimuth and stimulation design on well production and overall well economics.
The Bakken formation of the Williston Basin is undergoing significant development in Manitoba, Saskatchewan, Montana, and North Dakota. Numerous operators are active in the area, with a wide variety of development approaches. The industry has not yet reached consensus on optimal drilling and stimulation strategies.
Results indicate significant progress in improving well production, while reducing the drilled lateral length and the treatment size. Efforts to improve diversion and optimize proppant type and size appear to provide more effective fracture treatments, while eliminating production problems related to the flowback of frac sand.
This paper will provide the following benefits to readers: Operators in the Bakken have experienced significant problems with flowback of frac sand, requiring frequent pump changes, conservative production strategies, and expensive cleanouts prior to restimulation. This paper will describe the steps taken to eliminate proppant flowback into the wellbore and the estimated economic impact.This paper will provide a case study comparing the production from wells completed with a variety of strategies.The results suggest many current laterals drilled in the Bakken are ineffectively stimulated and demonstrate that significant increases in well profitability are possible with more optimized treatments.Optimizing fracture treatment designs for horizontal wells requires an estimation of the fracture geometry – particularly a description of the intersection between the wellbore and the fracture. A fracture treatment designed under the assumption of a longitudinal frac will be entirely inadequate if the actual fracture propagates in a transverse orientation. This paper will describe our understanding of the fracture geometry and how that has affected treatment designs.