bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experimental Study of Critical Flow Rates in the Tubing-Casing Annulus of Natural Gas Wells
Authors: Girija E. G. , Christiansen R. L. , Miller M. G. 
Published: December 2007

Abstract
Removal of water and hydrocarbon liquids from gas wells is increasingly recognized as an important topic for mature gas reservoirs. Accumulation of these liquids in the bottom of a gas well is often referred to as liquid loading. Liquid loading limits current productivity of 90% of the natural gas wells in the USA. Liquid loading first appears in the casing below the end of tubing (EOT). One way to reduce loading below the EOT is to install dead-end production tubing to the bottom of the perforations and force the gas to flow from the perforations through the tubing-casing annulus up to a cross-over connection near or above the top of the perforated interval. We conducted tests in a flow loop to evaluate such flow.
The primary objective of our tests was to determine the critical flow rates for two phase flow through tubingcasing annulus using two different tubing sizes (2.88-inch-OD and 3.50-inch-OD) in a 4.00-inch-ID casing. Secondary objectives were to develop a method to predict critical flow rate, to identify the flow regimes that exist at the critical flow rate, and to evaluate the mode of liquid transport.
For gas-water flow in vertical tubing, the Turner-Hubbard-Dukler (1969) prediction for critical flow rate (without the 20% correction) is very close to what we observe in our flow loop. However, the critical rates for flow in the tubing-casing annulus were found to be 20 to 50% less than predicted by multiplying the Turner-Hubbard-Dukler (THD) critical velocity and the annular cross-sectional area. It was observed from the tests that two types of flow regimes could occur at the critical flow rate: annular flow regime and transitional annular flow regime.
In flow through an annulus, the film thickness on the casing wall is larger than the film thickness on the tubing wall. Theoretical analysis for one-phase flow shows that the maximum velocity in tubing-casing flow is closer to the tubing. We believe that this observation also applies to two-phase flow and that the higher velocity near the tubing pushes liquid toward the casing, which results in the observation of thicker liquid films on the casing wall.
Estimating Reserves in Tight Gas Sands at HP/HT Reservoir Conditions: Use and Misuse of an Arps Decline Curve Methodology
Authors: Rushing J. A. , Perego A. D. , Sullivan R. B. , Blasingame T. A. 
Published: December 2007

Abstract
This paper presents the results of a simulation study designed to evaluate the applicability of an Arps1 decline curve methodology for assessing reserves in hydraulically-fractured wells completed in tight gas sands at high-pressure/high-temperature (HP/HT) reservoir conditions. We simulated various reservoir and hydraulic-fracture properties to determine their impact on the production decline behavior as quantified by the Arps decline curve exponent, b. We then evaluated the simulated production with Arps' rate-time equations at specific time periods during the well's productive life and compared estimated reserves to the true value. To satisfy requirements for using Arps' models, all simulations were conducted using a specified constant bottomhole flowing pressure condition in the wellbore.
Our study indicates that the largest error source is incorrect application of Arps' decline curves during either transient flow or the transitional period between the end of transient and onset of boundary-dominated flow. During both of these periods (principally the transient period), we observed b-exponents greater than one and corresponding reserve estimate errors exceeding 100 percent. The b -exponents generally approached values between 0.5 and 1.0 as flow conditions approached true boundary-dominated flow. Agreement between Arps' suggested b-exponent range and our results using simulated performance data also indicates that, if applied under the correct conditions, the Arps rate-time models are appropriate for assessing reserves in tight gas sands at HP/HT reservoir conditions.
Combined Seismic Inversion Methods in Reservoir Model Development
Authors: Wu Heyong , Wu Haibo , Wang Duanyang , Nian Jingbo , Sun Zhanqiang , Dusseault Maurice B. 
Published: December 2007

Abstract
Seismic inversion is the essential first step to ensure proper integration of seismic data, well log data, and geological and petrophysical information. In this article, we compare principles, key methods, work flow, advantages and disadvantages, and application conditions for several seismic impedance inversion methods that are in common use in the petroleum E&P community. Then, we present a case demonstrating successful and useful implementation of these integrated seismic inversion methods. From the seismic inversion practices developed, we conclude that good reservoir prediction results can be achieved by following a careful set of rules and a consistent work flow, reducing the inherent E&P risks. Part of this process is a formal approach to seismic inversion defined in three phases and nine steps.
Key Words: Seismic Impedance, Inversion Method, Reservoir Models, Work Flow, Integration, Earth Models.
Flooding Thin Low-Permeability Layers with a New Salt-Resistant, Medium-Molecular-Weight Polymer
Authors: Wang Duanyang , Li Shikui , Fan Chuanwen , Li Jingyan , Wu Haibo , Dusseault Maurice B. 
Published: December 2007

Abstract
Our interest is the enhancement of conventional oil recovery factors from thin low-permeability layers in a sandstone-shale sequence containing dozens of oil-saturated beds. Polymer flood is an option we have been using for many years in the Daqing Oilfield[1].
The physical chemistry performance, salt resistance performance, shearing resistance performance and aging stability of a new salt-resistant, medium molecular weight polymer (KY700) were evaluated by laboratory experiments. Results showed that the KY700 performs well and that its properties are particularly suited for thin, low-permeability layers, therefore field testing was undertaken. We present details of two full-scale field applications of the new polymer in two experimental areas in the Daqing Oilfield. In both cases, the injection and production profiles were significantly improved, oil production rates increased, and water production ratios decreased. The polymer appears to be a new and valuable product that can increase conventional oil recovery through polymer flooding of appropriate thin sandstone strata of moderate to low permeability.
A Procedure for Assessing the Value of Oilfield Sensors
Authors: Gilbert R. B. , Lake L. W. , Jablonowski C. J. , Jennings J. W. , Nunez E. J. 
Published: December 2007

Abstract
Spurred by advances in reliability, cost, and accuracy, sensors offer a means of increasing expected ultimate hydrocarbon recovery in drilling, in current production and in planned projects. Ultimate hydrocarbon recoveries larger than currently experienced are possible, especially when sensors are used with advanced recovery methods. However, often it is unclear if the incremental revenue generated will justify the cost of installing the sensors. Estimating this value is the goal of the work reported here.
Smart-Well Monitoring and Control: Snorre B Experience
Authors: Kulkarni R. N. , Belsvik Y. H. , Reme A. B. 
Published: December 2007

Abstract
Snorre B is a four-template subsea-development in the North Sea with a semi-submersible production platform. Today 10 of the 13 wells in operation are smart wells, each with up to four remotely operated downhole sleeves. Each downhole sleeve is equipped with pressure and temperature gauges on both the tubing and annulus side of the sleeve. Testing of each sleeve individually to establish water-cut, GOR, productivity index and reservoir pressure (collectively called the inflow performance) is costly and therefore not done frequently. This paper presents techniques to monitor smart well data, alerting users upon changes in inflow performance of sleeves. A technique to quantitatively estimate flow contribution of each sleeve from well flowtest data through a model based estimation program is also presented.
Several examples of the use of this technique in both production and injection wells are given. The new techniques presented for monitoring of smart wells and analysing smart well data lead to better understanding of reservoir drainage. This allows improved reservoir management and increased production.
Recent Developments in Risk Analysis—Applications for Petroleum Engineering
Authors: Cunha J. C. 
Published: December 2007

Abstract
Even though risk analysis has tremendous potential to be applied on various aspects of common problems in petroleum engineering, its use is not as widespread as it could be. This work presents some practical applications recent developed covering areas of well engineering, production and reservoir. The reason for presenting examples of such diverse areas is to emphasize the broad range of applications that are available. Emphasis of the paper will not be on the petroleum engineering aspects of the examples, but instead on the methodology used to incorporate risk analysis technique on practical problems faced by the industry.
Examples presented are either from actual industry applications or academic applications developed just to explore the possibilities of using decisions analysis for certain petroleum engineering issues.
The Role of Adsorption Isotherms on Chemical-Flooding Oil Recovery
Authors: Cardoso C. B. , Silva R. C. A. , Pires A. P. 
Published: December 2007

Abstract
The injection of chemical solutions plays an important role in increasing the recovery factor of mature fields. Compositional models considering adsorption phenomena describe polymer/surfactant flooding as a function of the chemical component concentration and salinity of reservoir/injection water. The concentration part of the solution for 1-D multicomponent polymer/surfactant flooding is completely defined by adsorption isotherm and is independent of relative permeabilities and phase viscosities. The one-phase displacement solution has been already developed and it is a well-known problem. The continuous injection of chemical solutions is a Riemann problem solved by introduction of a self-similar variable. In this paper the solution of the two-phase problem for chemical flooding is presented. It is considered the injection of two dissolved components considering adsorption phenomena for two different isotherms: Langmuir and Henry. A flow potential associated with the conservation of the aqueous phase is introduced as a new independent variable instead of time. This change of variables allows the system splitting in one equation and a thermodynamic system. The number of auxiliary equations is less than the number of equations in the compositional model by one. The solution of the thermodynamic part was done by the method of characteristics and it is completely determined by the adsorption isotherm. Once the two-component adsorption problem is solved, the two-phase flow behavior can be predicted. The applications include the choice of the chemical components to be injected for each reservoir, and also evaluate water compatibility. Another important utilization is testing of numerical compositional simulators by checking the independence of compositional dynamics on transport properties and by comparison of the numerical and analytical solutions. The obtained analytical solutions may be used in the development of streamline chemical EOR simulators.
Integration of Geochemical, Mud-Gas, and Downhole-Fluid Analyses for the Assessment of Compositional Grading—Case Studies
Authors: Elshahawi Hani , Hows Melton , Dong Chengli , Venkataramanan Lalitha , Mullins Oliver C. , McKinney Daniel , Flannery Matthew , Hashem Mohammed 
Published: December 2007

Abstract
Identifying compartmentalization, quantifying connectivity, and assessing the presence of compositional grading are critically important to reservoir management, particularly in deepwater projects where uncertainties are large and mistakes are costly. Compositional grading has been known for over 50 years, but the topic received little attention until the 1980's when sufficiently advanced analytical methods became available to assess the phenomenon. Individually, geochemistry, downhole fluid, and mud gas analyses have provided valuable insights into compositional grading, but each analytical method relies on different fluid traits and has different implications. When these analytic methods are systematically combined and consistently applied, the synergy delivers a much more accurate and robust picture of the reservoir and the fluids therein.
In this paper, we review two case studies in which we have combined multiple techniques for the assessment of compositional grading in different settings. We demonstrate that new technologies combined with real-time monitoring and control and a more integrated evaluation approach produce a more robust interpretation of the fluids and yield insights into reservoir architecture.
IPO Gas Lift Design Using Valve Performance
Authors: Decker Kenneth L. 
Published: December 2007

Abstract
Gaslift design has been practiced for many years using the Thornhill Craver (TC) equation to predict the rate of gas passage through a gaslift valve port but the TC equation and charts were never intended for use with live gaslift valves.
It is now possible to obtain tested valve gas passage performance data for any pressure and temperature conditions. To date, a method has not been provided for the use of this information during the design stage.
This paper will show how tested valve performance data can be used in the design of 1-inch (25.4 mm) Injection Pressure Operated (IPO) gaslift valves.
Spontaneous Imbibition in Small Cores
Authors: Olafuyi O. A. , Cinar Y. , Knackstedt M. A. , Pinczewski W. V. 
Published: December 2007

Abstract
This paper presents experimental data for co-current spontaneous imbibition into cores having bulk volumes from 0.1 to 12 cm3. Simple experiments of brine imbibing into air-filled cores were carried out. Homogeneous sandstone cores (Berea and Bentheim) and a carbonate core (Mt. Gambier) were used in the experiments. The experimental data were scaled using the scaling laws reported in the literature.
The results demonstrate that reliable experimental data of spontaneous imbibition can be obtained for the small cores of homogeneous porous rocks. Such data are of immense interest for validating the predictive value of network models based on micro-CT images of rock fragments with bulk volumes as small as 0.3 cm3. The data for cores of different sizes were satisfactorily scaled using five different methods[6, 11, 14, 15, 18]. The recovery models proposed by Ma et al.[15] and Viksund et al.[20] produced an excellent match for the normalized gas recovery data. Although the Li and Horne model[11] successfully correlated the imbibed water volume as a function of time, the model failed to correlate the normalized recovery data. A comparison of the scaled data with data previously reported for water-gas systems showed excellent agreement.
An Optimized Method to Remove Filter Cake Formed by Formate Based Drill-in Fluid in Extended Reach Wells
Authors: Alotaibi M. B. , Nasr-El-Din H. A. , Hill A. D. , Al Moajil A. M. 
Published: December 2007

Abstract
Smart, horizontal, and multi-lateral wells provide an attractive option for maximizing reservoir contact in both oil and gas fields in Saudi Arabia. Formate drill-in fluid has been selected lately for drilling gas wells, because of its ability to preserve conventional polymers at high temperatures. The formate salts also can reduce the rate of hydrolytic and oxidative degradation of many viscosifiers and fluid loss agents at high temperatures.
Drilling fluid filter cake can reduce the flow efficiency of cased or openhole wells. Calcium carbonate particles are frequently used as weighting material to maintain the pressure that is required for well control and minimize the leak-off. Such solids become consolidated and trapped in the polymeric material and this makes the filter cake a strong permeability barrier.
The conventional method for cleaning the filter cake is by circulating solids-free formate brines at a high flow rate. This mechanical technique removes only the external drilling fluid damage. Chemical fluids like acids, oxidizers or chelating agents are usually used as an alternative method for dissolving both the external and internal filter cake. Most of these fluids cannot give a full coverage to the wellbore due to the formation heterogeneity.
A new class of esters can generate an acid downhole at a low rate and distribute it uniformly through the wellbore. Fluid compatibility and thermal stability tests were studied in detail. Return permeability experiments were conducted by using HPHT dynamic fluid loss cells. The ester solution was effective in cleaning the filter cake in comparison to the formate brines completion fluid and other organic acids results. Also, circulating formate brine to restore the wellbore permeability or remove the internal filter cake damage was found to be insufficient. Surface tension measurements indicated that the generated alcohol and lactic acid from the ester solution had lowered the surface tension more than the formate brines.
Practical Analysis of Injection/Falloff Data of Horizontal Wells
Authors: Boughrara A A. , Reynolds A. C. 
Published: December 2007

Abstract
We have constructed new approximate analytical solutions for injection and falloff pressure response which include thermal effects that arise when flooding a reservoir with water having a temperature considerably below of that of the reservoir. We have developed an optimization code based on the Levenberg-Marquardt algorithm and coupled it with our new approximate analytical solutions to obtain a procedure for data analysis where our approximate analytical solutions are used as the forward model in the non-linear regression. We demonstrate that we can generate estimates of absolute permeabilities, the well skin factor, the length of the well and relative premeabilities by matching data to analytical solutions by minimization of a weighted least squares objective function. The relative permeability curves are constructed assuming a power law parametrization. In the horizontal well case, we show that the absolute permeabilities in the three principal directions can be resolved separately provided the duration of the test is sufficiently long.
Production Optimization in Closed-Loop Reservoir Management
Authors: Wang Chunhong , Li Gaoming , Reynolds A. C. 
Published: December 2007

Abstract
In closed-loop reservoir management, one periodically updates the reservoir model(s) by integrating production data, and then solves an optimal control problem to determine optimum operating conditions to maximize hydrocarbon production or net present value (NPV) for the remaining expected life of the reservoir. The cycle of updating and optimization is repeated at specified times. Here, to account for geological uncertainty, we suggest using the ensemble Kalman filter for reservoir model updating and consider three different algorithms for production optimization. A simple but representative example, indicates that the steepest ascent algorithm is the best of those tried, but if the required adjoint software for calculating the gradient of NPV with respect to the controls is not available, we show that if properly implemented, iteration using an easily computed stochastic gradient can yield a good estimate of the optimal NPV. For the problem considered, it is shown that NPV is a nonlinear function of the controls, but the final controls from cases with both known true geology and uncertain geology present "Bang-Bang" behavior.
A Critical Review for Proper Use of Water/Oil/Gas Transfer Functions in Dual-Porosity Naturally Fractured Reservoirs—Part I
Authors: Ramirez B. , Kazemi H. , Al-Kobaisi M. , Ozkan E. , Atan S. 
Published: December 2007

Abstract
Accurate calculation of multi-phase fluid transfer between the fracture and matrix in naturally fractured reservoirs is a crucial issue. In this paper, we will present the viability of the use of simple transfer functions to accurately account for fluid exchange resulting from capillary, gravity and diffusion mass transfer for immiscible flow between fracture and matrix in dual-porosity numerical models. The transfer functions are designed for sugar-cube or match-stick idealizations of matrix blocks.
The study relies on numerical experiments involving fine-grid simulation of oil recovery from a typical matrix block by water or gas in an adjacent fracture. The fine-grid results for water-oil and gas-oil systems were compared with results obtained with transfer functions. Both in water and gas injection, the simulations emphasize the interaction of capillary and gravity forces to produce oil depending on the wettability of the matrix.
In gas injection, the thermodynamic phase-equilibrium, aided by gravity-capillary interaction and to a lesser extent by molecular diffusion, is a major contributor to interphase mass transfer. For miscible flow the fracture-matrix mass transfer is less complicated because there is no capillary forces associated with solvent and oil; nevertheless, gravity contrast between solvent in the fracture and oil in the matrix creates convective mass transfer and drainage of oil.
Using the transfer functions presented in this paper, fracture and matrix flow calculations can be decoupled and solved sequentially–reducing the complexity of the computation. Furthermore, the transfer function equations can be used independently to calculate oil recovery from a matrix block.