bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Experimental and Theoretical Investigation of Upward Two-Phase Flow in Annuli
Authors: Lage Antonio C. V. M. , Time Rune W. 
Published: December 2007

Abstract
A mechanistic model is formulated to predict the mixture behavior for upward two-phase flow in concentric annulus. The model is composed of a procedure for flow pattern prediction and a set of independent mechanistic models for calculating gas fraction and pressure drop in bubble, dispersed bubble, slug and annular flow. In addition, some aspects of churn flow such as the slug/churn transition and the predictions of pressure drop are discussed.
A comprehensive experimental program was also launched to collect data. An extensive full-scale investigation was executed in a 1278 m vertical well with an 88.9 mm x 159.4 mm (3.5 in. x 6.276 in.) annulus. The test matrix covered the whole range of possible combinations of liquid and gas injection rates for an UBD operation in a similar geometry. Small-scale tests were also performed in a U-tube, which simulates the simultaneous injection of liquid and gas through the drill string. The U-tube apparatus comprehended a descending pipe (ID=34 mm=1.34 in.) and a 41 mm x 74 mm (1.61 in. x 2.91 in.) ascending annulus. Small-scale data available in the literature were also collected and catalogued.
The model is validated against the acquired database and shows a good performance for pressure drop prediction. Further, the performance of the model is also compared with other multiphase empirical or mechanistic models from the literature. The proposed model performs better than the other alternatives.
Infill Drilling in the Mississippi Limestone, Garfield County, Oklahoma
Authors: Maddox Gaiser D. 
Published: December 2007

Abstract
Development drilling of the Mississippi Limestone in southwestern Garfield County, Oklahoma, took place in the mid-1960's. Most of the development was either one well per quarter-section or one well per section, depending on the predominance of oil or gas in the hydrocarbon production.
In 1972, Union Texas Petroleum Division, Allied Chemical Corporation, drilled a second well on one of the quarter-sections to test the adequacy of the drainage by the original well. Results indicated that additional development was justified, and numerous new wells have been drilled since that time by Union Texas and by other operators as well. Drilling problems, completion techniques and some of the problems, completion techniques and some of the results obtained are discussed.

Introduction
The Mississippi Limestone is a massive fractured limestone underlying a large part of northwestern Oklahoma. It has been found productive of hydrocarbons in varying degrees productive of hydrocarbons in varying degrees over much of an area stretching from 12 miles east of Enid to 40 miles west and from 12 miles north to 15 miles south, give or take a few miles in any direction.
The specific part of this area to be discussed is north and west of the town of Waukomis, mostly in Township 21 North, Range 7 West. Most of this township had been developed in the mid-1960's with only one well per quarter-section, thought at the time to per quarter-section, thought at the time to be sufficient to recover the hydrocarbons which were economically recoverable. Some of the sections in the northern part of T21N and all of those in T22N had only one well per section, because they had been predominantly gas productive when completed. In 1972 the Exploration Department of Union Texas Petroleum prepared several maps contoured on Petroleum prepared several maps contoured on cumulative oil production through June 1971. The map of the Waukomis area indicated that the wells in T21N, R7W had recovered significantly more oil than in other areas, as shown in Figure 1.
The Mississippi Limestone has very low porosity, generally in the 3 - 6% range. porosity, generally in the 3 - 6% range. At the same time, this porosity is present throughout the entire thickness, which exceeds 500' in most of the wells.
Technology Applied to Extend the Drilling Reach of a Platform Workover Rig
Authors: McNair G. A. , Cassidy S. D. , Zheng Z. 
Published: December 2007

Abstract
The term "Extended Reach Drilling" refers to drilling operations conducted beyond the normal reach of drilling facilities. Typical problems associated with this type of operation are torque & drag limitations, wellbore stability, mud rheology and solids control and directional well design1,2,3. Such problems are particularly challenging to the CACT Operators Group due to limited platform rig size and platform deck space. These problems are further compounded by the fact that no spare well slots are available on the platforms, so all new platform drilling operations are sidetracks. This results in tortuous 3-dimensional well profiles that generate high levels of drilling torque and drag, disproportionate to the measured depth. The well planning and drilling practices used to drill these wells are very similar to those used in ultra-long extended reach wells and reflect the challenging nature of platform sidetrack operations.
This paper describes the challenges that are faced during development of the well plans and details the methods that are later used while drilling the sidetrack wells. Case histories with actual field data will show how the applications of the following new or emerging technologies have been applied successfully in the sidetrack program.
Borehole Stability Modeling was used to identify areas where the potential for borehole breakout and fluid losses (lost circulation) existed, so that plans could be made to avoid these problems. Real Time Downhole Data Measurements were used to provide instantaneous information on drilling conditions in order to avoid the problems experienced in previous wells. PDC bit designs, featuring low torque cutting structures to improve bit steerability were successfully applied on several recent sidetrack wells.
Effect of Mobile Oil on Residual Oil Saturation Measurement by Interwell Tracing Method
Authors: Tang Joseph S , Zhang Pei-Xin 
Published: December 2007

Abstract
Interwell tracing has been recognized as a reliable method for determining residual oil saturation between wells. Sponsored by the United Nations International Atomic Energy Agency, China Institute of Atomic Energy is currently conducting several tests in various China oil fields to determine residual oil saturation and to delineate reservoir problems. Interwell method assumes tracers contacting immobile oil in the watered-out zone and the oil saturation is calculated from the partitioning tracer propagation rate. In the presence of mobile oil, the partitioning tracer velocity would increase as it can contact, partition into and move with the flowing oil. As a result, assuming zero oil rate would lead to underestimate of oil saturation.
In an unsteady state displacement where tracers are injected with water into a virgin reservoir, the partitioning tracer will move with oil at a constant characteristic velocity governed by the partition coefficient. Since tracers are normally injected after the start of waterflood, the injected tracers will lag behind their respective characteristic fronts. The time required for the partitioning tracer to catch up with its characteristic front and the breakthrough time of the tracer in a pseudo 1-D system were theoretically analyzed in this paper. The produced oil cut, which is dominated by streamline distribution, sweep and layering, is not a definite indicator of mobile oil in the water zone. The presence of moving oil and its effect on oil saturation measurement can be inferred from the responses of two tracers with different partition coefficients.
Roundly Carry Out HSE Managed System Strengthen Construction of Enterprise Culture
Authors: Bo Zhang 
Published: December 2007

Abstract
This article began with the construction of enterprise culture.
It briefly introduced the contents of HSE management system. It further expaunded that the core of HSE management system was to produce the products and service, which fit for HSE, and about how to change the old management methods, how to operate HSE management system, how to strengthen the training of HSE adminstrative personels, and so on. Finally, the article indicated HSE management system was the cornerstone to establish the enterprise culture and the key to set up the favorable enterprise culture.
Oil and Gas Production and Environment Protection
Authors: Li Jin , Li Binyuan , Wang Chengwu , Chen Dajun 
Published: December 2007

Abstract
Oil and gas production cost keeps increasing because of going-up of water cut, going-down of oil connect, difficulty and expensive cost of treating polluted water. It is true especially for treating and discharging polluted water in Sichuan gas filed. Generally, oil and gas production procedures include producing oil of gas combined with water, separating oil or gas from water on surface, treating polluted water, and rejecting polluted water. The cost of treating polluted water is up to ¥20–30RMB/m3. The output of water on average is 60–80 m3/day and 200 m3/day maximally in the Northwest gas field of SPA. The cost of treating polluted water is about 30% of production cost, treat polluted water environment is the top goal for oil and gas company to pursuit. It is necessary to employ underneath close loop producing technology that oil or gas is separated underneath, polluted water is rejected, oil or gas is diverted on surface. The technology may in crease oil and gas production by 20–25%, due to increase of producing pressure drawdown, and reduce production cost by 50% because of improving working conditions of facilities, the cost of treating polluted water reduces by 50–60% and the pollution of water is avoided efficiently by employing new-type dual flow channel spiral separator.
Modeling Wellbore Dynamics During Oil Well Blowout
Authors: Hasan A. R. , Kabir C. S. , Lin D. 
Published: December 2007

Abstract
Blowout or uncontrolled flow of an oil well involves complex flow phenomenon involving transient multiphase flow and heat transfer in the wellbore. Various wellbore and reservoir parameters govern the maximum velocity attained in a given well. The maximum velocity may be either critical (sonic) or subcritical. This work adapts a transient model to capture the events leading to the onset of maximum velocity of a fluid mixture. The model uses a numeric method to solve the mass, momentum, and energy equations for the wellbore, and an analytic approach for fluid flow in the reservoir.
The theoretical sonic velocity computed by assuming isentropic expansion turns out to be higher than the actual maximum velocity attainable in the well. Computational results also show that the assumption of isentropic expansion becomes progressively worse with increases in gas/oil ratio, because of increased frictional loss. Among various parameters, the blowout rate increases with increased well-productivity index, flow-string diameter, reservoir pressure, and gas-oil ratio (GOR). The probabilistic reservoir-simulation approach is used to answer the reservoir-fluid–loss question.
Simplified Shaly Sand Analysis
Authors: Fertl Walter H. , Watt Harold B. 
Published: December 2007

Abstract
A simplified shaly sand analysis that uses a resistivity-one porosity log combination is discussed. The method involves estimation of shaliness by conventional techniques and, if necessary, porosity corrections for gas effects. A "pseudo-q" factor, which compares favorably with q-values from the Density-Acoustic combination, provides a basis for determining cutoff permeability. Computed water saturations compare well with the conventional Swq-equation.
The new method is applicable to minimum logging combinations as frequently run in development wells.

Introduction
Log analysis of shaly pay sands has received considerable attention. In many investigations, the clays and fluids occupying the interstices of the sand matrix are treated as a slurry, and the effect of both clay and hydrocarbons is taken into account. Based upon the dispersed clay model, the formation water saturation (Swq) has been estimated successfully in the U.S. Gulf Coast area for many years.
Resistivity of the disseminated clay (Rc)is not exactly constant. However, an average value should be useable for a given geological area, since under most circumstances even relatively large changes in the value of Rc cause only small variations in the computed water saturation. Generally, the resistivity of clays dispersed in the pore space of a reservoir rock is less than that of adjacent shales. Values of Rc = 0.5 Rsh for the shallow Wilcox of Louisiana and Mississippi have been given. For the Gulf Coast we recommend the use of Rc = 0.4 Rsh, which closely agrees with the concept of multiple Rw-values proposed previously. previously.

BASIC CONSIDERATIONS
Considering the response of porosity tools, such as the Density and Acoustic, to the shaliness of a formation, it is possible to compute water saturation, with one porosity tool only. In addition, it is then possible to derive a pseudo-q value, which gives an indication for the amount of clay in the formation and, therefore, estimates the likelihood for reservoir producibility. Response of Density and Acoustic logs in shaly, water bearing sands can be expressed such as:
..........Density........(1)
Fast Method for Real-Time Interpretation of Variable-Rate Wells with Changing Skin: Application to Matrix Acidizing
Authors: Ma L. , Johns R. T. , Zhu D. , Hill A. D. 
Published: December 2007

Abstract
Conventional well test analyses typically assume that the wellbore skin factor is constant over the entire duration of the well test. For certain cases such as during acidizing treatments, however, the skin factor can change significantly and affect the pressure response. The concept of well test analysis has been used in real-time evaluation of well stimulation treatments. Numerical and analytical methods have been developed to estimate the evolution of skin during acidizing, but these methods can be time consuming and cumbersome when numerous pressure and rate data exist.
In this paper, we apply the flow rate normalization method used in well testing to estimate skin as a function of time. We demonstrate that the new technique is accurate, robust, fast, and easy to use. We apply the method to two matrix acidizing treatments performed in a water well and an oil well. The skin calculations for each example agree well with those calculated from current accepted methods. The new technique is a fast, simple and more accurate method for real-time interpretation of acidizing treatments where a multitude of pressure and flow rate data exists. We compare the results from the new method to current methods for several field examples.
The Artificial Neural Network Method of Well-Test Interpretation Model Identification and Parameter Estimation
Authors: Deng Yuanzhong , Chen Qinlei , Wang Jiahong 
Published: December 2007

Abstract
A correct well-test interpretation model is the basement of well-test analysis, which is identified by the feature of pressure derivative curves. Automatic identification of well-test interpretation model is very important for automatic parameter estimation from the well test data. Based on the excellent performance of classification and the feature of noise insensitive, the artificial neural network (ANN) has been studied extensively in identification of well-test interpretation model. Whether the trained ANN can identify the interpretation model of the actual tested curve correctly depends on the ANN construction method. Using the derivative curve's data point series as input vector to train ANN can't ensure the actual tested curve in the same model area as it training samples. So the sample curves data point series trained ANN usually misidentify the interpretation model of the actual tested curve. Based on the pressure derivative curve's common features among different interpretation models, an ANN approach is proposed to realize the type curves matching and move the tested curves to its sample position. Using curve's binary numbers instead of data points as input vector to train ANN can guarantee the actual tested curve in the same model area as its training samples, this ensure the successfully trained ANN can identify the interpretation model of the actual tested curve correctly. The examples showing that the proposed method is more efficiently than the data point series method. In the process of interpretation model identification, the parameters can also be estimated.
Reservoir Management in Maturing Oil Field
Authors: Pan Zhijian , Mu Longxing , Hong Liu , Yao Wenguang 
Published: December 2007

Abstract
The terrestrial reservoirs in China are mainly under waterflood development. Now these oil fields are generally running into mature waterflooding with 82.5% of water cut during which the oil field productions decline faster. As to the fact that the annual productions and remaining recoverable reserves still take a very important role in the oil industry, the advanced investigation and management on improved oil recovery in maturing fields have to be focused to keep the oil production stable and success in both economic and social benefits. Based on the determination of three kinds of factor controlling the distribution of remaining recoverable reserve[1], such as heterogeneity, fluid flow behavior in pore media and oil field development procedure, this paper presents integrated approaches to description of shale or flow barrier on waterflooding, heterogeneity on the basis of statistical geologic modeling and sedimentary petrography, and reservoir flow unit or hydraulic unit. By going through the single sand development procedure and fluid flow mechanism in heterogeneous pore media, the remaining reserve distribution and development in a reservoir with 95% of water cut have been explored.
Condensate Banking Dynamics in Gas Condensate Fields: Changes in Produced Condensate to Gas Ratios
Authors: Zhang H. R. , Wheaton R. J. 
Published: December 2007

Abstract
A general theoretical treatment of condensate banking dynamics was developed previously by Wheaton and Zhang1 to show how the compositions of heavy components of a gas condensate change with time around production wells during depletion. This current paper presents further analytical development of condensate banking dynamics on the behavior of produced condensate to gas ratios.
In this paper, a general theoretical treatment is attempted to show how the produced condensate to gas ratio varies with time during pressure depletion. Numerical simulations are pursued to confirm and supplement the theoretical analysis. Numerical welltest results and in particular liquid gas ratios are interpreted with the developed analytical model. The effects of low permeability and reservoir heterogeneity on condensate banking are discussed in terms of condensate to gas ratios.
Results have shown that no natural steady state exists with regard to condensate to gas ratio. Well tests to obtain data relating to the initial condition of the reservoir are not reliable once bottom hole pressure falls below dewpoint. The level of heterogeneity has a significant impact on the way a condensate bank develops. Only if pressure rises within condensate banking region following a period of depletion, will condensate to gas ratio increase and be greater than the initial condensate to gas ratio value. The condensate to gas ratio is very sensitive to the heterogeneity level in the reservoir and it is in itself an important indicator of reservoir heterogeneity.
In summary, the objectives of this paper together with our previous study of compositional changes are to introduce novel theoretical treatments to form a foundation for increased understanding of the condensate banking processes and of the well deliverability impairment.
Converting Gas into Liquid Fuels to Develop RCD Field, Central Sumatera, Indonesia
Authors: Arianto Indria Doria 
Published: December 2007

Abstract
Gas-to-Liquids (GTL) technology is a technology to converts natural gas into synthetic liquid hydrocarbon. This technology can be used for marginal gas field, can reduce gas-transportation costs, and helps satisfy the demand for cleaner fuels. The process of this technology consists of two steps, synthesis gas ("syngas") formation from natural gas, and synthetic liquid fuel formation using Fischer-Tropsch reaction. Synthetic liquid fuels produced from natural gas have long been known as the cleanest fuels available. RCD field located in Jambi area, approximately 60km South West Jambi, Central Sumatera, Indonesia. Discovered at 1985, RCD field developed as an oil field although geologic evaluation and seismic interpretation discovered large oil and gas reserves. This gas reserves currently undeveloped due to a limitation of gas markets. To develop RCD gas reserves, 18.6 MMscfd natural gas for 20-year production time can be converted into 1860-bpd synthetic liquid fuels consists of naphtha, kerosene, and diesel. Economic analysis indicates that converting into liquid can be used to commercialize RCD gas reserves with 5.54-year of payout time and 20.69% internal rate of return. Transformed into liquids, RCD gas reserves would be developed and have an access to markets through conventional oil infrastructure. This development would not only impact oil and gas supply, but also help to meet environmental requirements.
Optimising the Development of Blake Field under Tough Economic and Environmental Conditions
Authors: Du K. E. , Pai S. , Brown J. , Moore R. M. , Simmons M. 
Published: December 2007

Abstract
This paper summarises the studies performed during the optimisation of the Blake Field Development (UK) in the low oil price environment prevailing in 1999 and concurrent with the introduction of new tighter environmental regulations aimed at reducing the emission of greenhouses gases in the UK industry. It describes the technical work carried out up to the sanction of the project. The paper focuses on the principles and assumptions that determined the field development plan prior to the development drilling. The following aspects are addressed in the paper: 1) utilisation of existing infrastructure to economically develop marginal fields, 2) use of reservoir modelling techniques to optimise well placements, completion strategies and topside capacities, 3) practical means of managing reservoir uncertainties/risks during the development drilling and 4) application of updated reservoir management practices, with particular emphasis on the management of gas and water coning and on the development of this high permeability reservoir coincident with a thin column of fully saturated oil.