bluuebunny/crossref_metadata_2025_split huggingface dataset:
Formation Rate Analysis in an Anisotropic Formation and It's Practical Applications
Authors: Sheng James J. , Georgi Dan T. , Mezzatesta Alberto , Lee Jaedong 
Published: December 2007

ProposalIn probe-type formation tests, due to the geometry of the wellbore and the sealing effect of mudcake, the flow pattern is not perfectly spherical. To account for the deviation from spherical flow, several geometric correction factors were proposed for different analysis techniques. A geometric factor is used in Formation Rate Analysis (FRA), a technique used in analyzing a probe test to estimate formation pressure and permeability. Like other geometric correction factors, the geometric factor is a strong function of permeability anisotropy that is generally unknown before a test. When analyzing the test, we would logically assume an isotropic formation and use the corresponding geometric factor. Consequently, the FRA estimated permeability does not represent the true spherical permeability. In contrast, the spherical permeability can be estimated from buildup analysis without prior knowledge of permeability anisotropy. Therefore, the discrepancy between the permeability estimates from the two analysis methods cannot be resolved. In addition, if separately considered, neither FRA nor buildup analysis can decompose the estimated permeability into its horizontal and vertical components.This paper presents the derivation of numerical values of several geometric correction factors. Using the concept of geometric factor, we resolve the discrepancy between the permeability estimates from FRA and buildup analysis. This paper also presents procedures to estimate horizontal and vertical permeabilities by combining FRA and buildup analysis or by combining buildup analysis and pressure history matching. These procedures are verified with a simulated probe test. An example of an actual test analysis is also presented.
Experimental Study of Phase Transformation Effects on Relative Permeabilities in Fractures
Authors: Chen Chih-Ying , Li Kewen , Horne Roland N. 
Published: December 2007

Abstract
Phase transformation affects multiphase flow in geothermal and gas-condensate reservoirs due to the same substance occurring in different phases. These effects change the phase behavior and the flow characteristics. The goals of this research were to compare the flow behavior and relative permeabilities difference between two-phase flow with and without phase transformation effects in smooth-walled and rough-walled fractures. During this research, an experimental apparatus was built to capture the unstable nature of the two-phase flow fractures and display the flow structures in real time. Two-phase flow experiments with phase transformation effects (steam-water flow) and without phase transformation effects (nitrogen-water flow) were conducted. The porous medium approach was used to calculate two-phase relative permeabilities. From the results in this study, steam-water relative permeabilities are different from nitrogen-water relative permeabilities. The enhanced steam-phase relative permeability is due to the effects of phase transformation. This shows consistency with some earlier studies in porous media. The nitrogen-water relative permeability is described most appropriately by using the viscous coupling model. However, steam-water flow in the rough-walled fracture, which is coupled with strong phase transformation effects, seems to be represented better by Brooks-Corey relative permeability functions for fractured media (λ →∞). The results from this study suggest that relative permeabilities accounting for phase transformation effects have to be used in simulations of geothermal and solution gas reservoirs to represent two-phase interactions adequately.
Effect of Elastic Behavior of HPAM Solutions on Displacement Efficiency Under Mixed Wettability Conditions
Authors: Huifen Xia , Ye Ju , Kong Fanshun , Wu Junzheng 
Published: December 2007

Abstract
In this paper, the oil displacement efficiencies of viscous-elastic HPAM solutions and viscous glycerin solutions are studied by flooding at visual microscopic glass models. Also, the effect and mechanism of the viscous-elastic behavior of HPAM solutions and glycerin solution on the displacement of residual oil films under mixed wettability conditions and residual oil at blind-end are studied, the relationship between the elastic behavior of HPAM and oil displacement efficiencies is given. The results of rheological characteristic measurement indicate that both the viscosity and the first normal stress differential (N1) of HPAM solutions increase with the increase in concentration, HPAM solutions show strong viscous-elastic characteristics under high concentration conditions. The results of microscopic oil displacement experiments indicate the displacement efficiencies of HPAM solution flooding and glycerin solution flooding gradually increase with the increase in the viscous-elastic behavior of HPAM solutions and the viscosity of glycerin solutions. However, for HPAM solution flooding, the displacement efficiency is always higher and residual oil saturation lower than that of glycerin at the same viscosity and same capillary number and at the same oil saturation after water flooding.
Uncertainties in Standard Analyses of Boundary Effects in Buildup Data
Authors: Larsen Leif 
Published: December 2007

Abstract
Boundary effects are often observed in buildup data, or at least that is the conclusion frequently drawn from an observed increase in derivative on a loglog plot or increase in slope on a semilog plot. Furthermore, if for instance it is concluded that effects of a sealing fault is seen in a given data set, then simple line methods or direct analytical modelling efforts are normally used to determine the distance to the boundary. A sealing fault is the normal choice of boundary model if a doubling is observed in derivative or semilog slope. If a 4-fold increase in derivative is observed, then a model with the well placed somewhere between two sealing faults forming a right angle would be a normal choice. But what if the two faults are not sealing? If the flow capacity on the other side of the faults is only one third of the value on the well side, what will be the derivative characteristics?
Problems like these are addressed in detail in the paper, with a series of simple rules given for possible combinations that will generate buildup data of a specific type, i.e., with a specific "familiar characteristics." The rules can be used to list alternatives interpretations without running separate analyses. For instance, it is shown that the derivative characteristics of any sector model bounded by sealing faults corresponds to an infinite number of 2-zone sector models with angle between the boundaries and permeability contrast satisfying a single equation. Other pairs of models with similar characteristics are models with partially sealing faults and specific 3-zone sector models, and either of these types of models and radial composite models. This clearly complicates analyses.
Also addressed are problems related to possible differences in the boundary effects observed in drawdown and buildup data for certain models. As one example, U-shaped and sector models can have identical buildup characteristics over a wide time range although drawdown data from the models have distinctly different boundary characteristics. Radial composite and composite sector models are also of this type, with potentially significant differences between drawdown and buildup data. The reason for bringing up such cases is to emphasize the importance of attempting to collect high quality drawdown data in addition to buildup data to limit the range of possible interpretation models.
For completeness, effects of uncertainties in basic input parameters on the final analyses are also covered in the paper.
The Analytical Solution for Wellbore Stability in Multilateral Junctions in Nonhydrostatic In-Situ Stress Field
Authors: Hoang S. , Abousleiman Y. , Tare U. 
Published: December 2007

Abstract
Wellbore completion and stability in multilateral junctions to date presents one of the most challenging operations to field engineers. Given the complex geometry of the multilateral junction, comprehensive mechanical stability and well completion have not yet been fully investigated. In this paper, the newly-derived analytical solution for the stress in and around the junction in a non-hydrostatic state of in-situ stress for an open-hole completion is used to assess the overall stability of the multilateral junction. This study models the main wellbore and the lateral wellbore as two circular holes in an infinite plane, with various radii and variable separation distance, thus simulating the multilateral junction extension. The system is subjected to the in-situ minimum and maximum principal stresses, with variable wellbore pressures and mudweights. The theoretical solution is used to reproduce the stress distribution in and around a multilateral junction, of an equivalent experimental program conducted and published in paper SPE 78212. This paper shows that the relative orientation of the junction to the in-situ stress field and the radii's ratio of the main wellbore to lateral wellbore both have a significant impact on well completion, stability, and stress distribution in and around the multilateral junction.
Pressure-Transient Analysis of Dual Packer-Probe Wireline Formation Testers in Slanted Wells
Authors: Onur M. , Hegeman P. S. , Kuchuk F. J. 
Published: December 2007

Abstract
This paper examines the use of spatial pressure transient measurements acquired by packer-probe wireline formation testers (WFT) in slanted (deviated) wells for estimating formation parameters; e.g., horizontal and vertical permeabilities, skin, tool storage coefficient as well as initial formation pressures. The well's inclination angle ranges from 0 to 90°, covering vertical and horizontal wells as limiting cases. New approximate analytical equations for spherical flow, which is often exhibited by dual-packer interval and observation probe(s), are presented. These analytical equations are valid for all inclination angles and provide a technique for determining formation parameters from spherical and/or radial flow exhibited by packer and probe(s) pressure transient measurements in slanted wells for single layer systems. These equations also provide a useful set of good initial parameter estimates when nonlinear regression analysis is employed for parameter estimation. It is shown that nonlinear regression provides a useful analysis procedure to identify the formation parameters that can be uniquely determined from different sets of spatial pressures measurements of packer/probe WFTs. A field dual-packer/probe test example is provided to illustrate the methodology and procedures developed in this work.
Compositional Modeling of Fractured Reservoirs Without Transfer Functions by the Discontinuous Galerkin and Mixed Methods
Authors: Hoteit H. , Firoozabadi A. 
Published: December 2007

Abstract
In a recent work, we introduced a numerical approach that combines the mixed finite element (MFE) and the discontinuous Galerkin (DG) methods for compositional modeling in homogeneous and heterogeneous porous media. In this work, we extend our numerical approach to fractured media. We use the discrete fracture model (crossflow equilibrium) to approximate the two-phase flow with mass transfer in fractured media. The discrete fracture model is numerically superior to the single-porosity model and overcomes limitations of the dual-porosity model including the use of a shape factor. The MFE method is used to solve the pressure equation where the concept of total velocity is invoked. The DG method associated with a slope limiter is used to approximate the species balance equations. The cell-based finite volume schemes that are adapted to a discrete fracture model have deficiency in computing the fracture-fracture fluxes across three and higher intersecting fracture branches. In our work, the problem is solved definitively due to the MFE formulation. Several numerical examples in fractured and unfractured media are presented to demonstrate the superiority of our approach to the classical finite difference and finite volume methods.
Well Test Characterization of Small- and Large-Scale Secondary Porosity in Naturally Fractured Reservoirs
Authors: Rodríguez Fernando , Arana-Ortiz Victor , Cinco-Ley Héber 
Published: December 2007

Abstract
An analytical model to characterize secondary porosity in naturally fractured reservoirs through well testing is presented in this paper.
The physics of this model is based on the well known fact that secondary porosity, fractures and vugs, occurs at various scales in a naturally fractured carbonate reservoir. It is also driven by requirements found while modeling and matching fluid flow behavior of actual fields, regarding the need for consideration of small and large scale secondary porosity systems, as documented in a companion paper.
Based on these facts, a nested-triple-porosity singlepermeability model for the pressure transient behavior of a well producing in a naturally fractured reservoir is here developed. Three porosity systems, acting at different scales, are assumed to coexist in a fractured reservoir: matrix, small-scale and large-scale secondary porosity media. Flow in series among these media is considered: The matrix exchanges fluids with the small-scale secondary porosity, which in turn feeds the large-scale secondary porosity. The first two media are assumed to have a local effect on fluid flow and are handled as discontinuous while the third, the large-scale secondary porosity medium, is considered to affect fluid flow at the reservoir scale and is hencefore continuous.
Solution to the above mentioned problem provides distinctive well pressure transient behavior that can be used to characterize nested triple porosity by well testing methods. Main parameters describing the pressure behavior of the reservoir under consideration and the role that they play on the pressure response of a well are discussed. Conditions under which the nested-triple porosity character of a reservoir could be established are documented.
A procedure to characterize triple-porosity singlepermeability naturally fractured reservoirs is developed and applied to field data.
Reliability Assessment in Deepwater Intervention Planning Based on Available Field Data
Authors: Frota Helder Mamede 
Published: December 2007

Abstract
This work is related to the reliability engineering, specifically, to the analysis of data lifetime and to the modeling of well failures and its causes from a major production development project in Campos Basin, Brazil. The data gathering encompasses 12 years of well intervention experience, which originated a summary; a consistent data base to work with, including the indication of the real reason of each intervention. To this data base, which is restricted to satellite offshore oil wells connected to production platforms in water depths ranging from 500 to 1,500 meters, it was incorporated the annual growth of wells population. It is worth to mention that, in this particular deep water scenario, the database available for the study is unique. The area of failure modeling in association with well interventions behavior is the focus of this study. It was obtained the pattern of the interventions and extracted the wanted data: types and failure modeling, durations, annual frequencies, and number of interventions. The results can be used in economical analysis, maintenance prediction and in reliability studies. Therefore, the importance of this study relies on the application of a methodology as an alternative to reduce the subjectivity in investment decision making concerned to the oil well intervention planning.
Integrating Pressure Data from Formation Tester, Geochemical Fingerprinting, and PVT Studies to Characterize Deep Gas Reservoir Continuity and Compartmentalization: Case Study
Authors: Raba'a Ali S. , Nagel Arvo 
Published: December 2007

Abstract
The paper presents a case study in which pressure data from wireline formation tester tools, geochemical fingerprinting of hydrocarbon liquids, and comparison of PVT properties has assisted the initial reservoir characterization of a deep gas-condensate accumulation in Saudi Arabia. The work has confirmed fluid type, contacts, formation connectivity, and has been a useful complement to conventional seismic and geological data interpretations done for the field. This has been particularly important for this large field which is being fast tracked for development by Saudi Aramco with limited existing well control. The results of the data integration have been instrumental in:
Quantifying the extent and connectivity of reservoir units. Assessing reservoir quality for completion design. Constructing geologic and reservoir simulation models for field-development planning.
The field of interest is located south of Ghawar in Saudi Arabia and contains rich gas-condensate reservoir fluids. The reservoir rock comprises an unconsolidated and heterogeneous sandstone known as the ‘Unayzah-A formation. Reservoir characterization based on seismic, geologic and petrophysical analysis has indicated 10 stratigraphic units within the main ‘Unayzah-A reservoir. The ‘Unayzah-A consists of well-developed eolian sandstones and closely associated inter-dune and lacustrine deposits. The dune and sheet sandstones of the eolian facies show the best reservoir quality. In contrast the inter-dune and lacustrine deposits have much poorer rock quality.
The subject work comprised acquisition and analysis of wireline formation tester pressure data from seven wells, geochemical fingerprinting studies conducted on DST condensate samples from three wells, and review of hydrocarbon gas PVT properties from two wells. The formation tester information identified vertical and lateral connectivity of various ‘Unayzah-A zones throughout the field. Geochemical fingerprinting and PVT analysis have supported the interpretation of the formation tester data. These data have been integrated into the geological and petrophysical interpretations to refine the 10 geological layers into 4 generalized flow units for use in reservoir modeling. The results helped design completion targets in existing wells and locate new wells.
Acoustic Stimulation to Mitigate Near-Wellbore Damage
Authors: van der Bas Fred , Rouffignac Eric de , Zuiderwijk Pedro , van Batenburg Diederik 
Published: December 2007

AbstractNear-wellbore formation damage reduces the productivity in most of the existing oil and gas wells. The formation damage is caused by the invasion of fluids during the drilling and completion process and in a later stage by the deposition of particles (fines, scale, asphalthenes, etc) due to production. The conventional technique to remove these types of damage is injection of fluids to dissolve the damage. The treatments typically involve pumping of chemicals (acid, corrosion inhibitor etc.) under matrix conditions. Controlled placement of the treatment fluids in the zones that need to be treated is difficult and sometimes impossible in particular in long, horizontal intervals.A promising new technique to remove the near-wellbore damage is high-frequency acoustic stimulation; a specially designed acoustic tool is utilized on wireline or coiled tubing to selectively treat the required reservoir intervals. The preferred application of this tool is at underbalance pressure condition: damage particles mobilized by the acoustic waves are removed from the reservoir interval by the production flow. The paper reports on the ongoing acoustic stimulation research.Laboratory work showing the potential of acoustic cleaning has been previously reported; it was performed on sandstone cores saturated with brine in a laboratory set-up using linear acoustic waves. Recent acoustic cleaning experiments examined the effect of various other conditions i.e. oil saturated rock and gravel pack completion. Results from these experiments are presented here.
Use of Material Balance to Enhance 3D Reservoir Simulation: A Case Study
Authors: Esor Eugene , Dresda Stefano , Monico Carlo 
Published: December 2007

Abstract
Material balance evaluation (MBE) has long been identified as a useful means of establishing connected hydrocarbon volume initially in place and reservoir drive mechanism1,2. Analysis of MBE results can also prove invaluable in addressing questions on reservoir compartmentalisation and fluid contacts.
This paper demonstrates the application of MBE in narrowing down the above uncertainties prior to a full 3D numerical simulation study. The scope covers 9 reservoirs in the Niger delta area of Nigeria as part of a broader study.
The aims of the MBE were to guide the construction of more realistic 3D simulation models by establishing connected hydrocarbon volumes and addressing uncertainties in reservoir compartmentalisation and hydrocarbon contacts. Furthermore, the MBE was aimed at facilitating more efficient history matching by establishing the reservoir drive mechanisms beforehand.
The candidate reservoirs, which range from undersaturated oil to gas condensate with varying aquifer strengths, have long history of production and adequate pressure measurements, making them ideal candidates for reliable MBE.
The MBAL™ software was used to carry out the MBE. A combination of the analytical non-linear regression and the linear (P/Z, Havlena-Odeh etc) methods was used in establishing the correct material balance model, thereby giving confidence in the obtained results.
The paper presents the study background, introduction, methodology, results, conclusions and recommendations.
Results from the MBE showed the connected hydrocarbon volumes for all the reservoirs and established compartmentalisation in 2 of the reservoirs; communication across a fault in 1 reservoir; and homogeneity in the remaining 6 reservoirs. This information was applied to the 3D simulation models by assigning appropriate transmissibility values across the relevant faults. The results also established the need to adjust Hydrocarbon contact in one of the reservoirs. Furthermore, the established historical drive mechanisms helped in obtaining faster and more reliable 3D history match.