bluuebunny/crossref_metadata_2025 huggingface dataset:
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

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

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

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

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

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

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

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

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

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

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

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

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

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

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.
Enterprise Risk Management in the Petroleum Industry Through Information Validation
Authors: Randall Scott W. , Griffin Don P. , Harrell D. Ronald
Published: December 2007

Shareholders, board members, regulators and the general public are demanding reasonable assurance of value growth, governance and compliance through corporate level risk management at petroleum exploration and production companies. However, at the heart of this assurance is the reliability of information. Petroleum reserves estimating and reservoir engineering techniques provide assurance around the reliability of estimated hydrocarbon quantities. These same techniques can be combined with tools from the fields of operational risk management and strategic planning to support the emerging practice of Enterprise Risks Management (ERM) at oil and gas companies. This paper presents a framework for achieving reasonable assurance of the reliability of information to support ERM at oil and gas companies through use of a various tools and techniques.

Using examples from integrated multinational upstream companies, it is shown how qualitative and quantitative tools could be tied together into a systematic ERM process that complies with minimum standards for information integrity. Reference is made to the Resource Management System approved in 2007 by the SPE Board and its industry partners AAPG, WPC and SPEE and its guidance on principles of reserves estimating as an example of best practice in validating information. Sample data from the field of reserves estimating and resource estimation is presented to illustrate information validation approaches.

The value of reliable information to support enterprise risk management is demonstrated by showing how various stakeholder groups are satisfied through reasonable assurance. In turn, this assurance leads to competitive advantage for oil and gas companies in terms of cost of capital, reduced regulatory scrutiny, and improved strategic focus.

Operational risk management tools and techniques have been used for many years in functional areas ranging from petroleum geology to major project and commodity price risk management. However, techniques from the broader fields of strategic planning, market research and quality management have not been integrated with methods from petroleum reserves and resource classification to manage enterprise level risks. This paper suggests that an information validation framework supported by tools and techniques from beyond the field of operational risk management can provide petroleum companies with sustained competitive advantage.
Achieving Superior Application Engineering: Proven Holistic Approach Disseminated to a Wider Community Key to Success
Authors: Redshaw J. P. , Scotchman A. D. , Laing R. , Dwyer J. P. , Trichel D. K.
Published: December 2007

Delivery of performance through reduced well time while maintaining optimum wellbore quality requires a thorough understanding of the drilling environment, recognizing geological and drilling process hazards. Studying each component of the drilling system and environment in isolation prevents identifying the root cause of or fully understanding the problem, leading to less than optimal solutions and failure to deliver performance. To overcome performance barriers, we must first have an in-depth understanding of the root cause by taking a holistic approach to the analysis of the drilling environment.

This organization developed a successful process within a dedicated drilling optimization group that enabled a structured approach to understanding the complete drilling environment. This successful process, founded on the continuous improvement cycle—plan, execute, analyze, and capture— delivered practices and technology recommendations to realize performance gains and significant well-time reduction. Taking lessons learned from one well and implementing these on subsequent wells delivered further performance improvements.

The original drilling optimization group comprised a small team of highly disciplined engineers focused on detailed application analysis to minimize barriers to drilling performance improvement. This group's work was the foundation of drilling knowledge tools within the organization; this work led to the development of industryleading methodologies for data analysis and best drilling practices.

The performance advantages realized by the team using this process lead the organization to recognize that its wider drilling community would benefit from the use of this process to deliver consistent performance gains.

The authors will describe the process and how it has been applied to the wider drilling community to meet the needs of individual engineering disciplines and groups.

The challenge to distribute the holistic approach and continuous improvement philosophy from a core group to the wider organization involved raising competency standards and the provision of dedicated knowledge transfer tools, creating an enabling environment to allow proactive performance management of specific applications. Finally, the authors will present several case studies that document success with the process.
Estimation of Formation Stresses Using Radial Variation of Three Shear Moduli—A Case Study From a High-Pressure and High-Temperature Reservoir in a Norwegian Continental Shelf
Authors: Sinha Bikash K. , Vissapragada Badarinadh , Wendt Anke S. , Kongslien Marit , Eser Hakan , Skomedal Eiliv , Renlie Lasse , Pedersen Erik Sandtorv
Published: December 2007

Formation stresses and rock strength together with wellbore and pore pressures are important inputs to failure models whose predictions help in well planning, wellbore stability and production. A complete characterization of formation stresses requires estimation of the overburden, maximum and minimum horizontal stresses together with pore pressure as a function of depth. The overburden stress is reliably estimated by integrating with depth the formation bulk density, and pore pressure is directly measured in a permeable reservoir interval. The maximum and minimum horizontal stresses can be estimated from borehole sonic data in the presence of crossing dipole dispersions. A new stress magnitude estimation algorithm inverts radial variation of the three shear moduli together with the overburden stress and pore pressure at a given depth for the maximum and minimum horizontal stress magnitudes and formation nonlinear constants referred to a local reference state. The algorithm uses equations relating differences in the dipole shear moduli at two radial positions and corresponding differences in the principal stresses obtained from near-wellbore stress concentrations using the Kirsch's equations. Radial positions in the plastically yielded region close to the borehole surface are excluded from the inversion algorithm.

Processing of sonic data yields crossing dipole dispersions in three sand intervals in a development well drilled in a high pressure (770 bars) gas condensate field operated by Statoil in the Norwegian continental shelf. Results for both the maximum and minimum horizontal stress magnitudes are consistent in the three sand intervals in the Bent reservoir of the Kvitebjorn field. Estimated minimum horizontal stress magnitude is in good agreement with the mini-frac test conducted at a nearby depth. The maximum horizontal stress direction coincides with the fast-shear azimuth obtained from the Alford rotation of cross-dipole waveforms. Horizontal stress magnitude results have helped in refining the mechanical earth model and in subsequent drilling of development wells in this field.
Grid Modeling and Numerical Simulation of Multiphase Flow in Heterogeneous Reservoirs Using Orthogonal Collocation Schemes
Authors: Abhulimen Kingsley E. , Anubi Moses O.
Published: December 2007

Complex features such as geological features (e.g. faults, pinch outs, inclined beddings); well related (multilateral wells of general orientation) can have significant impact on reservoir performance as well as reservoir fluid flow. These features are difficult to model using traditional finite difference methods, hence sophisticated gridding and discretization techniques are required if their effects are to be captured accurately in numerical reservoir flow simulators. Our model for reservoir stimulation uses advanced orthogonal collocation numerical simulators as well as grid transformation of the Cartesian coordinates (x, y, z) into curvilinear coordinates (ξ(r), ξ(θ), ξ(z)) to accommodate general three dimensional deviated wells and complex reservoir geometry for both structured and unstructured geology for multiphase flow of hydrocarbon in complex reservoir formations. Our model was applied to simulate multiphase flow in complex reservoir formations in Nigeria using a sophisticated computer numerical program developed in mathlab to model for pinch outs, well deviated formations using different mix of injectors-producers schemes. Data was sourced from an operating oil company typifying some complex reservoir formations. It is now possible to determine non-conventionality of a reservoir and actually determine where and when it sets in by studying both the pressure and flow performance plots. It is clear that non-conventionality of reservoir is more important at the center of the reservoir payzone coordinates. Using our transformed coordinates, we located non-conventionality of the reservoir system at ξ (r ) = 0.42566 Non-conventionality in the studied reservoir is determined from increase activity in flow and pressure deviation charteristics as observed around the coordinates ξ(r) = 0.42566 using inference of the flow and pressure performance plots.
Enabling Automated Workflows for Production
Authors: Szatny Michael
Published: December 2007

The Oil & Gas industry faces manpower, equipment, and service shortages as it tries to cope with a world energy demand that is projected to grow from 230 million barrel of oil equivalents per day (boe/d) today to 335 million boe/d in 2030. As such, it will rely heavily on technological advances to meet future energy demands. Additionally, the most experienced engineering staff will retire in the next 5-10 years. Therefore, significant workforce productivity gains will have to be realized through digital oilfield automation initiatives to manage future levels of E&P activity.

Many production workflows require engineers to coordinate data flows between disparate numbers of applications. Studies have shown that about 70% of an engineers time is spend gathering, formatting, and translating data for use in these different applications. For standard production activities, ie. workflows, this time can be drastically reduced by creating an automated system to execute the prescribed workflow. The automated workflow not only reduces the engineers valuable time doing these repetitive tasks, but also ensures consistency in methods, reduces the likelihood of input errors, and creates a repository for "best practices" that can be maintained long term as personnel (and their knowledge) is moved into and out of the production asset.

For many years automated workflows have been a part of the design and production cycles in other industries like Aerospace, Automotive, and Industrial Manufacturing. These industries have been tying together applications and data sources along with using stochastic analysis methods and optimization to improve their overall productivity.

This is exactly what the Oil & Gas industry needs today. The tools used to orchestrate these workflows across a wide variety of applications, requirements and IT systems have matured to a state that the creation of new automated workflows is virtually "plug & play".
A Basic Approach to Wellbore Two-Phase Flow Modeling
Authors: Hasan A. R. , Kabir C. S. , Sayarpour M.
Published: December 2007

This study presents a simplified two-phase flow model using the drift-flux approach to well orientation, geometry, and fluids. For estimating the static head, the model uses a single expression for liquid holdup, with flow-pattern-dependent values for flow parameter and rise velocity. The gradual change in the parameter values near transition boundaries avoids discontinuity in the estimated gradients, unlike most available methods. Frictional and kinetic heads are estimated using the simple homogeneous modeling approach.

We present a comparative study involving the new model as well as those that are based on physical principles, also known as semimechanistic models. These models include those of Ansari et al, Gomez et al., and OLGA. Two other widely used empirical models, Hagedorn and Brown and PE-2, are also included. The main ingredient of this study entails the use of a small but reliable dataset, wherein calibrated PVT properties minimizes uncertainty from this important source.

Statistical analyses suggest that all the models behave in a similar fashion and that the models based on physical principles appear to offer no advantage over the empirical models. Uncertainty of performance appears to depend upon the quality of data input, rather than the model characteristics.
Effects of Reservoir Heterogeneities on the Steam-Assisted Gravity Drainage Process
Authors: Chen Q. , Gerritsen M. G. , Kovscek A. R.
Published: December 2007

The success of steam-assisted gravity drainage (SAGD) has been demonstrated by both field and laboratory studies mostly based on homogeneous reservoirs and reservoir models. A comprehensive understanding of the effects of reservoir heterogeneities on SAGD performance is required, however, for wider and more successful implementation. This work presents a numerical investigation of the effects of reservoir heterogeneities on SAGD using a stochastic model of shale distribution. Two flow regions, the near well region (NWR) and the above well region (AWR), are identified to decouple the complex effects of reservoir heterogeneities on the SAGD process. Numerical simulations are conducted with various realizations of shale distribution to compare SAGD performance in terms of the effects of NWR and AWR. Hydraulic fracturing is proposed to enhance steam chamber development for reservoirs with poor vertical communication and the feasibility of hydraulic fracturing is discussed in terms of in-situ stresses and well orientations. Fracturing the formation around both the injection and production wells is found to improve steam distribution, oil production rate, and the oil-steam ratio.
Real-Time Performance Analysis of Water-Injection Wells
Authors: Izgec B. , Kabir C. S.
Published: December 2007

This work presents a complete reformulation of the Hall method involving both pre- and post-breakthrough situations. Two approaches involving both transient and material-balance methods produced very similar solutions, which were verified with the results of coupled geomechanical/fluid-flow simulations. The new formulations allow tracking the expanding water-bank radius from inception to breakthrough. Pressure of this bank at the water/oil interface is evaluated at every timestep, thereby allowing continuous update of the ‘external pressure’ in Hall's formulation. We show that Hall's formulation is a particular case of the proposed approach. Several simulated and field examples demonstrate the value of reformulated Hall analysis.

Because Hall formulation involves an integral, the resultant signature, by nature, is insensitive in revealing clues about subtle changes that may occur during formation fracturing or plugging. We observed that the derivative of modified-Hall integral, obtained analytically, provides definitive signatures about fracturing or plugging.

The new interpretation approach is particularly suitable for projects at the inception of flooding. Mature projects can benefit equally from the new tool. Perhaps the biggest appeal of the proposed tool lies in the green fields, where real-time data are readily available.
Use of Artificial Intelligence Techniques for Predicting Irreducible Water Saturation - Australian Hydrocarbon Basins
Authors: Goda H. M. , Maier H. R. , Behrenbruch P.
Published: December 2007

Determination of original hydrocarbon in place, OHIP, is a vital task in petroleum development. The estimation of appropriate rock and fluid properties is a requirement, with irreducible water saturation, Swir, being one of the key parameters. A representative Swir is also required when conducting multi-phase experiments, for example relative permeability determination. Furthermore, Swir has an influence on residual oil saturation during tertiary recovery.

Conducting primary drainage capillary pressure experiments to measure Swir is the industry-established practise. Such experiments tend to require considerable resources and long time periods to complete. As a consequence, a limited number of representative core plugs are typically considered, often leading to data gaps for some facies within a reservoir. In such situations, an empirical model may be useful in predicting Swir.

In a recent study, artificial neural networks have been applied successfully to the estimation of irreducible water saturation (Swir) for Australian formations. The model demonstrates a superior performance when compared with other, conventional models. This paper features the translation of the artificial neural network model into a simple mathematical equation that is suitable for quick hand calculation. Moreover, a new semi-empirical model to predict Swir is presented, containing five adjustable constants. The optimal values for these constants were obtained by minimizing the calculated error utilizing a genetic algorithm. Both neural network and semi-empirical models were developed, calibrated and validated by using an extensive data set gathered for Australian hydrocarbon basins.
LBC Viscosity Modeling of Gas Condensate to Heavy Oil
Authors: Yang Tao , Fevang Øivind , Christoffersen Kjell , Ivarrud Endre
Published: December 2007

Due to simplicity, consistency and flexibility, the Lohrenz-Bray-Clark (LBC) correlation is the most widely used viscosity model in reservoir engineering. Unfortunately the LBC viscosity model does not accurately predict liquid viscosity. Consequently it is necessary to tune the calculated viscosities. Tuning of the LBC viscosity model is normally performed by modifying the critical volumes of the C7+ components and/or the LBC coefficients. The tuning procedure is not straight forward. Special attention is required for three challenging fluid systems: viscosity of the condensed oil from gas condensates, viscosity changes in connection with gas injection and viscosity of heavy oils.

This paper describes guidelines for proper tuning and consistency checking of the LBC viscosity model. Instead of using various correlation-estimated critical volumes for the C7+ components as in most PVT software, the initial critical volumes of the C7+ components are calculated based on component viscosities estimated from a dead-oil empirical correlation. Global regression to the measured viscosity data is then made with modifiers to the initial critical volumes. This procedure guarantees monotonically increasing component viscosities for the C7+ components. In the case of any regression on LBC coefficients, it is very important to maintain a monotonic relation of viscosity vs. reduced density.

Viscosity data from three Norwegian offshore reservoirs, from gas condensate to heavy oil, are used as examples. The guidelines for tuning the LBC viscosity model presented in this paper provide practical insight and understanding of how to apply the LBC viscosity model to various fluid systems.
Managing Total Circulation Losses with Crossflow While Drilling: Case History of Practical Solutions
Authors: Suyan K. M. , Dasgupta D. , Sanyal D. , Sharma Vinod , Jain V. K.
Published: December 2007

Lost circulation during drilling increases the drilling costs and also enhances possibility of stuck pipe. Generally, viscous mud pills with lost circulation materials and gels or cement plugs are placed to allow plugging of loss circulation zone. But in case of total circulation loss in conjunction with cross flow condition, even repeated LCM-mud plugs followed with cement plugs do not guarantee the durable sealing of lost zone. This paper discusses the properties, mechanism and placement technique for successful plugging off lost zone in such cases where very few lost circulation remedies were effective and more than several hundred cubic meter of drilling fluid and cement were already lost.

Details development of a novel sealant system consisting of an elastomer combined with cross-linking polymers, activator and bridging agents which provided quick, reliable control of loss has been deliberated in this paper. Initial low viscosity of this sealant allow easy placement against the lost zones and then gel activated near wellbore to set and form a stiff, rubbery gel stick with formation sediments to eliminate further losses. This development offers a proven means of controlling severe circulation losses resulting from large fractures or vugular spaces. The composition can be engineered to produce durable cross-linked polymeric rigid gel across a vide range of densities 8.6-14 ppg and temperature 45120 deg C. Addition of accelerators or retarders during mixing controls setting time and eliminates risk of premature setting inside the string while pumping.

Laboratory tests revealed effectiveness of this polymeric based sealant treatment and can improve stress around wellbore by forming a deformable, viscous and cohesive sealant inside a lost circulation fracture. Field application shows the restoration of well bore integrity in total loss with cross flow condition by the innovative approach of using this cross linked polymeric stiff rubbery gel in combination with high volume cement plug.

This paper deals with aspect of important lessons learnt from the field application of the developed cross linked polymeric stiff rubbery gel to control total circulation losses in conjunction with cross-water flow.
Design of Carbon Dioxide Storage in a North Sea Aquifer Using Streamline-Based Simulation
Authors: Qi Ran , Beraldo Valcir , LaForce Tara , Blunt Martin J.
Published: December 2007

We propose a carbon storage strategy where CO2 and brine are injected into an aquifer together followed by brine injection alone. This renders 80-95% of the CO2 immobile in pore-scale (10s μm) droplets in the porous rock; over thousands to billions of years the CO2 may dissolve or precipitate as carbonate, but it will not migrate upwards and so is effectively sequestered. The CO2 is trapped during the decades-long lifetime of the injection phase, reducing the need for extensive monitoring for centuries. The method does not rely on impermeable cap rock to contain the CO2; this is only a secondary containment for the small amount of remaining mobile gas. Furthermore, the favorable mobility ratio between injected and displaced fluids leads to a more uniform sweep of the aquifer leading to a higher storage efficiency than injecting CO2 alone.

This design is demonstrated through the incorporation of a recent model of trapping and relative permeability hysteresis based on pore-scale modeling into a field-scale streamline-based simulator. One-dimensional results are verified through comparison with analytical solutions. Results are then shown for storage in a North Sea aquifer. We design injection to give optimal storage efficiency and to minimize the amount of water injected; for the case we study injecting CO2 with a fractional flow between 85 and 100% followed by a short period of chase brine injection gives the best performance.
Carbon Dioxide Transport and Sorption Behavior in Confined Coal Cores for Enhanced Coalbed Methane and CO2 Sequestration
Authors: Jikich Sinisha A. , McLendon Robert , Seshadri Kal , Irdi Gino , Smith Duane H.
Published: December 2007

Measurements of sorption isotherms and transport properties of CO2 in coal cores are important for designing enhanced coalbed methane/CO2 sequestration field projects. Sorption isotherms measured in the lab can provide the upper limit on the amount of CO2 that might be sorbed in these projects.

Because sequestration sites will most likely be in unmineable coals, many of the coals will be deep and under considerable lithostatic and hydrostatic pressures. These lithostatic pressures may significantly reduce the sorption capacities and/or transport rates. Consequently, we have studied apparent sorption and diffusion in a coal core under confining pressure. A core from the important bituminous coal Pittsburgh #8 was kept under a constant, threedimensional external stress; the sample was scanned by X-ray computer tomography (CT) before, then while it sorbed, CO2. Increases in sample density due to sorption were calculated from the CT images. Moreover, density distributions for small volume elements inside the core were calculated and analyzed. Qualitatively, the computerized tomography showed that gas sorption advanced at different rates in different regions of the core, and that diffusion and sorption progressed slowly. The amounts of CO2 sorbed were plotted vs. position (at fixed times) and vs. time (for various locations in the sample). The resulting sorption isotherms were compared to isotherms obtained from powdered coal from the same Pittsburgh #8 extended sample.

The results showed that for this single coal at specified times, the apparent sorption isotherms were dependent on position of the volume element in the core and the distance from the CO2 source. Also, the calculated isotherms showed that less CO2 was sorbed than by a powdered (and unconfined) sample of the coal. Changes in density distributions during the experiment were also observed. After desorption, the density distribution of calculated volume elements differed from the initial distribution, suggesting hysteresis and a possible rearrangement of coal structure due to CO2 sorption.
A Dual-Grid Automatic History-Matching Technique With Applications to 3D Formation Testing in the Presence of Oil-Based Muds
Authors: Malik Mayank , Torres-Verdín Carlos , Sepehrnoori Kamy
Published: December 2007

Probe-type formation testers are often used to estimate permeability and permeability anisotropy from pressure transient measurements. The interpretation of these measurements is not trivial in the presence of oil-base mudfiltrate invasion due to miscibility with formation oil and gas. Simple analytical expressions of spherical and linear singlephase flow may not give correct estimates of permeability in miscible or partially miscible flow regimes. A computationally demanding three-dimensional (3D) numerical model is required to provide accurate and reliable estimates of formation properties. Because pressure transients are nonlinearly dependent on the permeability of the formation, repeated 3D numerical simulations are necessary to match the measured pressure transients.

We describe the development and successful implementation of a new inversion method that efficiently estimates permeability and permeability anisotropy with a cascade sequence of least-squares minimizations. Measurements consist of pressure transients acquired at the sand face with a probe-type wireline formation tester (WFT). The new inversion method executes the forward 3D problem only in an outer loop. In the inner loop, we perform fast minimizations with an equivalent two-dimensional (2D) cylindrical grid. Transient measurements of pressure at the sand face simulated with the 2D cylindrical grid are correlated to the corresponding measurements simulated with the 3D grid. Once the 2D minimization is completed, we perform a 3D simulation of transient pressure to update the 2D-3D correlation parameter and a new 2D minimization is performed until convergence is reached. The process repeats itself until the simulated 3D pressure transients reproduce the field measurements within pre-stipulated error bounds.

We perform tests of the new inversion algorithm on synthetic and field data sets acquired in the presence of oil-base mudfiltrate invasion. Results successfully confirm that our coupled 2D/3D hybrid inversion approach enables significant savings in computer time and provides reliable and accurate estimates of permeability and anisotropy. In most cases, we are able to estimate permeability under 2% error within 20% of the computational time required by 3D minimization. Sensitivity analysis indicates that permeability estimates may be biased by noisy measurements and uncertainty in (a) flow rates, (b) relative permeability, (c) radial extent of invasion, (d) formation damage, and (e) location of bed boundaries.