bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Transient Multi-Phase Flow Simulation using Steady-State Correlations for Coiled-Tubing Applications – New Insights to Old Problems
Authors: Salim P. , Aitken B. , Li J. 
Published: July 2010

Abstract
In the past four decades, several computer programs have been developed to predict steady-state fluid flow in coiled tubing (CT) applications. They are useful in designing the ultimate treatment phase of an intervention but questions remain concerning how their results are affected by the transient nature of the overall job. Any change in the operating conditions on surface or down hole will introduce a transient response. Common treatments such as liquid unloading, under balanced drilling with nitrified fluid, well control, cementing and hole cleaning may never reach a steady state. Only a transient simulation can determine whether a steady state is achieved. If it is not, the simulation can be used by job programmers to develop procedures that will deal with transient phenomena.
This paper describes a transient multi-phase flow simulation that has been developed based on the correlations used to describe steady-state multi-phase flow. The software was extensively validated against data collected on a full scale flow loop, field operations, and other transient software. Several field cases are used to illustrate the transient nature of CT applications and the benefits of using the transient simulation for the operational design, training and job execution.
Fishing Live Perforating Guns Stuck in the Wellhead: The Challenges and Obstacles
Authors: Powers J. L. 
Published: July 2010

Abstract
The Piceance Creek field is a high pressure gas field located in the northwest corner of Colorado and production is from multiple zones at depths in the order of 12,000ft. Standard well construction in the field takes the form of monobore completions with several sets of perforations producing commingled. Typical exploitation techniques involve the perforating, fracturing and cleanup of the lowest zone followed by each successive zone being completed in the same manner by running a composite bridge plug and perforating guns on the same run in the well using electric line methods.
In a recent well completion procedure the same techniques were used however, on one of the later runs, the composite bridge plug preset at a depth of 75ft while going in the hole resulting in a fish at surface straddling the lower part of the tree with the perforating guns still attached to the bridge plug and with high pressure at the wellhead. The only alternative available was to pull out of the e-line rope socket and attempt to fish the guns. Subsequent attempts to fish the guns with wireline techniques designed to shear out the plug setting tool resulted in two additional fish being left in the hole with the upper end straddling the tree and the swab valve. This presented a unique set of circumstances which required extremely careful handling in order to prevent a major well control problem.
In this paper the author will describe the subsequent operations which were performed to remedy the situation and bring the well back to a productive condition and all the challenges associated with it. This included freezing the wellhead to allow removal of the wireline lubricator and the upper part of the wireline fish followed by the installation of additional upper master/swab valves and a fishing operation using coiled tubing. Finally the plug was milled and full access to the well achieved, all without any HSE incident.
A General Coupled Kinetic Adsorption/Precipitation Transport Model for Scale Inhibitor Retention in Porous Media: I. Model Formulation
Authors: Sorbie K. S. 
Published: July 2010

Abstract
The application of scale inhibitors to prevent mineral scale formation downhole is performed routinely in the oil industry in chemical "squeeze" treatments in water producing wells. The retention of scale inhibitor (SI) within the formation is central to a squeeze treatment having a long lifetime. Scale inhibitors are retained within porous media by the two main mechanisms of "adsorption" (Γ) and "precipitation" (∏). There is not complete agreement in the literature about when we should use one mechanistic description or another. Field observations are not sufficiently accurate to distinguish between different retention models/mechanisms and a detailed analysis of a given retention mechanism requires carefully designed laboratory experiments at "field relevant" conditions. In previous experimental and modelling work (SPE 114108), we have demonstrated for static (equilibrium) "apparent adsorption" tests where the system exhibits either (a) adsorption only or (b) it is in the coupled adsorption/precipitation (Γ/∏) regime. Results from an extensive series of "apparent adsorption" experimental measurements were presented for various mineral separates to illustrate these points.
In addition to experiments, we must also have well developed models which can describe these retention processes both for equilibrium Γ/∏ cases and also for kinetic flowing situations where the processes are not at equilibrium. That is, a complete model of SI retention must have (i) an equilibrium description of the coupled Γ/∏ process (SPE 114108); (ii) a kinetic model of coupled Γ/∏ which correctly limits to the equilibrium case (i.e. the kinetics must be consistent with the equilibrium Γ/∏ model as t → ∞); (iii) the full kinetic Γ/∏ model must then be embedded in a transport model for flow through porous media. In this paper, the two tasks in (ii) and (iii) are carried out; a fully cononsistent coupled Γ/∏ is developed and then incorporated into a transport model (a 1D core flood simulator) and a number of example simulations are carried out. In the related Paper II (SPE 130703), the application of this coupled model in a sensitivity study of field squeeze treatments is described.
Material Selection for HP/HT Developments
Authors: Marsh J. , Zvandasara T. , Macgill A. , Kenny J. , Kenny J. P. 
Published: July 2010

Abstract
This publication examines the material selection challenges for offshore High Pressure (HP) and High Temperature (HT) developments, both present and future. The materials are examined from corrosion/cracking, mechanical performance and economic perspectives. The scope of this publication includes subsea equipment and pipelines and is oriented towards subsea developments. It does not include wells, wellheads and trees, though the material selection experience and literature for these have been reviewed. The parameters examined include material resistance to corrosion and cracking from a variety of mechanisms, costs of materials, mechanical strength, retention of mechanical properties at elevated temperatures, and requirements for dealing with forces associated with longitudinal stress such as upheaval buckling. Methodologies for control of temperatures and pressures, such as cooling spools, are also discussed. Different operators have different philosophies towards material selection for HP/HT developments, and the chosen materials range from carbon steel to super duplex stainless steels and nickel alloys. The duplex type stainless steels can offer excellent corrosion resistance and mechanical strength, especially 25% Cr super duplex. However, as temperatures increase, these materials suffer from a steep decline in mechanical strength. Also, the susceptibility to hydrogen induced stress cracking (HISC) can place severe limits on the allowable stress levels. They are also expensive materials with long delivery times. Carbon steel suffers in terms of corrosion resistance, even with corrosion inhibition, as inhibition becomes problematic at elevated temperatures. However, the loss of mechanical strength is less marked, and corrosion can be mitigated by the use of corrosion resistant alloy (CRA) cladding if required. The super modified Martensitic 13% Cr materials have excellent mechanical strength, very good retention of strength even at high temperatures, and low cost. However, they are less resilient in terms of corrosion and cracking resistance and are highly susceptible to HISC. Materials selection is affected by a large number of variables, and by the relative conservatism of the operator. Pipeline and subsea equipment design needs to be flexible in response to these requirements. This becomes especially challenging for future developments, where increased temperatures may require solutions out with those traditionally utilized.
Application of Thermal Recovery and Waterflood to Heavy and Extra-heavy Oil Reservoirs: Analog Knowledge from More Than 120 Clastic Reservoirs
Authors: Lu X. G. , Sun S. Q. , Xu J. 
Published: July 2010

AbstractMore than 120 clastic reservoirs were examined to extract knowledge of application of thermal recovery and waterflood to heavy or extra-heavy oil (less than or equal to 25 °API gravity). The thermal recovery methods discussed include cyclic steam injection, steam flood, in-situ combustion, hot water injection and SAGD. Key parameters of reservoir and fluid properties and production engineering are summarized in detail for reservoirs where one or more of the above EOR methods or waterflood are applied. These include: (1) reservoir characteristics such as sandbody facies type, permeability, porosity, oil saturation, reservoir depth, net pay thickness and net to gross ratio; (2) crude oil properties including API gravity, viscosity, GOR, and FVF; (3) well spacing and ultimate recovery factor; and (4) controls on incremental recovery and ultimate recovery factor.Controls on ultimate recovery factor for each of the above methods were analyzed. It was found that the basic controls are API gravity, viscosity, reservoir depth, net to gross ratio and well spacing. Thermal recovery methods are mainly applied to reservoirs less than 1100 m deep with crude oil API gravity less than 20°, and typical well spacing of 2–5 ac. The ultimate recovery factor is variable, ranging from 9% to 79%. The most commonly applied thermal recovery methods are cyclic steam injection and steam flood. In-situ combustion has also been successfully applied to some reservoirs with ultimate recovery up to 45%. SAGD technique applied to extra-heavy oil reservoirs is able to improve recovery by 45% to 50% of STOIIP.Waterflood, which has been widely applied to relatively "light" heavy oil with API gravity greater than 15°, can yield good recovery provided that well spacing is close and throughout injection is sufficient. The secondary recovery method is usually implemented in reservoirs at depths greater than 600 m with well spacing of 6–50 ac. Typical ultimate recovery factors for reservoirs with waterflood ranges from 20% to 45%.
A Study for Redevelopment Trends after Polymer Flooding and Its Field Application in La-sa-xing Oilfield
Authors: Dandan Hu , Wei Tang , Yuwen Chang , Yuanbing Wu , Songhao Hu 
Published: July 2010

Abstract
La-sa-xing oilfield of Daqing in China, which accomplished polymer flooding in quick succession, had now entered into subsequent water flooding stage with yearly increase reserves, so various development contradiction were serious, the effect of conventional measures by water flooding were poor, the potential oil-bearing areas became complicate and were increasingly difficult to be produced.
The paper proposed redevelopment trends after polymer flooding for La-sa-xing oilfield, on the basis of analysis of residual oil distribution and present technologies of EOR after polymer flooding, includes subdivision of layer series of development, well pattern reconstruction, application of horizontal well to producing residual oil in the top of thick layer, using high concentration polymer, comprehensive implementation of various optimization measures and accelerating tertiary oil recovery technique etc.
The paper took the typical block of North 1 Area in Sazhong oilfield as a case study, established detailed reservoir geological model and carried out reservoir numerical simulation, made clear residual oil characteristics and residual oil distribution law after polymer flooding and calculated residual oil potential after polymer flooding. The paper provided a technical strategy and ideology for recombination of layer series of development and combined well spacing of horizontal and vertical wells, and formed a set of post-polymer-flooding's optimization and adjustment technology of vertical well infilling, combination of horizontal and vertical wells and re-polymer-flooding. The paper developed EOR mechanism simulation research for further enhanced recovery optimization. Numerical simulation results of optimization plan indicated that recombination of layer series of development and combined production by using horizontal-vertical wells is a feasible and effective way to improve further development effectiveness and the incremental recovery rate can reach to 5%.
A New BHA's Thoeretical Analysis and Its Successful Applications
Authors: Zhu Xiaohua , Jia Yanjie , Tong Hua 
Published: July 2010

Abstract
This paper presents a new Flexible Bottomhole Assembly (BHA), which is classified as a coupled driven drilling BHA of the power anti-deviation, with the technical superiority of anti-deviation and high ROP. The coupled driven drilling has simultaneously two driving powers: one is from kelly/rotary-table or top-drive; another is from positive downhole motor (PDM). Comparing with the traditional BHA, the new BHA for coupled driven drilling uses a short flexible sub and the appropriate PDC bits with high hydraulic efficiency and high cleaning and cooling capacity, which has rationally distributed the stabilizers' spacing, and has scientifically designed the structure of PDM centralizer's size.
The new BHA used for coupled driven drilling is based on an integrated mechanical model. Through the analysis on the kelly/rotary-table and rotor centrifugal force and their transmission efficiency, the fulcrum role to PDM centralizer and its leverage ratio, the formation force and the geometric anti-deviation force, and the coupling analysis on the above factors, this paper has set up an anti-deviation force's calculation model of the coupled driven drilling, a relationship model between the allowable well-deviation and the critical WOB, a PDC bit gauge length design model, and the structural designed model of PDM centralizer. According to the above integrated model from the view of the whole system, a set of software moduli, a coupled driven drilling BHA mechanical analysis and drilling parameters optimization, is developed to determine the optimum BHA through different formation parameters, drilling parameters, the design requirements to well-deviation and ROP. The new BHA and the matching technology have been in successful application in the part of oil blocks of the Bohai Sea in China, the ROP and well-deviation meet the design requirements, and borehole quality has been improved significantly.
Studies on Fracture-identification of the Igneous Rock Reservoir by Well Logging
Authors: Wang Jianguo , Liu Hongqi , Zhao Xuan 
Published: July 2010

Abstract
This paper mainly focuses on the igneous rock reservoirs of Yingcheng group in Xushen gas field, Daqing. According to plenty of data in field (Core description, conventional logging, FMI, drilling data), this work presents the general development characteristics of core fractures, the response feature of fractures in conventional well logging and FMI, then, an quantitative fracture-identification criteria has been established with the method of curve unit-principle and algorithm.
Compared with the identification results of conventional well logging, FMI shows a significant advantage of fracture characterization in most cases. In some local low-resistivity formations, conventional well logging could serve as an assist method in collating the results of FMI to distinguish the low-resistivity caused by fractures.
Results provided through practices and research in this paper demonstrates that combining FMI with the conventional well logging can lead to a creative and feasible method in identifying fractures in the igneous rock, and shed some light on related researches on other complex reservoirs, such as metamorphic rock, carbonate rock, and tight sand oil gas reservoirs.
Rebuilding Existing Geological Models
Authors: Da Veiga S. , Le Ravalec M. 
Published: July 2010

Abstract
Reservoir models must be fully updateable: when new data become available, the optimal model identified from a first matching process must be modified to honor also these newly collected data. Therefore, a new matching process has to be run starting from the previously matched model.
A facies realization can be modified by varying either facies proportions or facies spatial distributions. The gradual deformation method was introduced to perturb facies distributions (Hu, 2000). This parameterization technique involves a reduced number of parameters and allows for preserving the spatial variability of facies. The resulting changes can be global or localized over a target sub-domain. Local gradual deformation is possible only when applied to the random numbers used to generate the facies realization. Therefore, a prerequisite is to know the random numbers used to produce the existing matched reservoir model.
However, in many cases, especially when the second matching study is performed a significant time after the first one, the random numbers are no longer available. The only known object is the realization describing the spatial distribution of facies. At this point, the problem to be solved consists of identifying random numbers, which allow for generating a stochastic realization close to the one populating the existing geological model. In this paper, we develop different methods for identifying the required random numbers and reconstructing the existing reservoir model. Three cases are considered: the existing model was generated from the Sequential Indicator Simulation algorithm, the truncated Gaussian method, or the pluri-Gaussian method.
The potential of our methodology is illustrated from a few realistic examples. A particular application shows how an object-based facies realization can even be modified, while considering a reconstruction process based upon the truncated Gaussian method.
Research and Application on CO2 and Dissolver Assisted Horizontal Well Steam-injection to Develop Super Heavy Oil
Authors: Hui Li , Jianfang Sun , Junping Shi 
Published: July 2010

Abstract
The Super heavy oil in the Shengli Oilfield is commonly higher than 20×104mPa•s in ground degassing viscosity and deeper than 1000m in depth, and therefore the traditional development techniques such as steam-injection is not effective due to the high steam-injection pressure and little heat radius. The study of flow shows that the super heavy oil is dilatant fluid in porous media, the temperature transform to Newton fluid and the startup pressure gradient are higher than other heavy oil, and the oil drainage radius inferior to the heating radius. In order to improve the injection steam quality and enlarge steam sweep, proposed new technique that combing the steam injection with horizontal well assisted by CO2 and dissolver agent to develop super heavy oil. Lab experiment shows that the high efficient dissolver agent may decrease the viscosity of the heavy oil around the well hole and increase the injection steam quality; meanwhile, the CO2 may enhance the injection steam volume and enlarge the drainage radius effectively. By means of the plug injection of dissolver agent and CO2 assisted horizon well the super heavy oil may be recovered effectively. Moreover, well pattern and distance and the economic-technique limit are studied by numeric simulation. Based on the research, the thermal chemical technique is completely developed, and is very effective for the development of super heavy oil. Moreover, it is of practical significance which has been evidenced and applied in the field such as Zheng 411 block, Tuo 826 block and Shan 113 block with about 5000×104t reserve being developed.
Comparison of Oil Displacement by Water Between Naturally Fractured Reservoir and Vuggy Fractured Reservoir Based on Streamline Technique
Authors: Zhang Xuelei , Hu Yongle , Fan Ru , Li Baozhu , Zhang Shouliang 
Published: July 2010

Abstract
The differences between naturally fractured reservoir and vuggy fractured reservoir are apparent in the aspect of oil displacement by water. In fractured reservoir, the oil displacement by water is the governing recovery mechanism known as capillary imbibition, which allows the recovery of matrix oil that cannot be reached by the externally applied pressure gradients of waterflooding. The main difficulty is the problem of choosing the well pattern. While oil displacements in the vuggy fractured reservoir are dependent on the single well huff-and-puff because of its higher permeability and the nonexistence of the coning, thus its displacement is to inject water by production well, and the mechanism is to complement formation energy and replace rather light oil with water by gravity segregation.
In this paper, the displacement models of naturally fractured reservoir, which are based on streamline numerical simulation method, are developed and discussed on the well pattern, well type, recovery rate, injection rate, injection cycle, etc. The result shows that design of well pattern plays a dominating role in the waterflooding, followed by the optimization of injection rate. While for the vuggy fractured reservoir, injection cyclic deserves prior consideration. The other factors such as critical recovery rate, critical injection rate, injection opportunity, aquifer, etc. are also taken into account in the study, which make the development scenario of vuggy fractured reservoirs more reasonable and economic.
In the end, an example of comparison between Fuyu oilfield(naturally fractured reservoir) and Tarim oilfield (vuggy fractured reservoir) is presented to illustrate the differences of the displacement, and scenarios suited for the reservoir are put into implementation. The study provides an important technical support for similar reservoirs development, especially when confronted with the problem of oil displacement at the secondary recovery stage.