bluuebunny/crossref_metadata_2025 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

Proposal

In 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

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

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

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

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

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

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

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

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

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

Near-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

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.
Modeling Conformance as Dispersion
Authors: Coats K. H. , Whitson C. H. , Thomas L. K.
Published: December 2007

For decades the effect of physical dispersion (in-situ mixing) in porous media has been of interest in reservoir engineering and groundwater hydrology. Dispersion can affect the development of multi-contact miscibility and bank breakdown in enriched gas drives and miscible solvent floods of any mobility ratio.

The magnitude or extent of dispersion is quantified by the rock property physical dispersivity (α) which is the order of 0.01 ft for consolidated rocks and several times smaller for sand-packs, from many laboratory measurements.

Numerical studies of the effect of dispersion on enriched gas drives and field tracer tests often use input values of dispersivity 100 to 1000 or more times larger than ~0.01 ft. These large input dispersivity values stem from large apparent dispersivities (αa) determined by matching the one-dimensional convection-diffusion (1D CD) equation to production well effluent tracer concentration profiles observed in field tracer tests.

The large apparent dispersivities reflect conformance or other behavior not governed by the 1D CD equation and should not be used to justify large physical dispersivity as input to numerical studies. This paper shows that large apparent dispersivities observed in field tests can result with physical dispersivity no larger ~0.01 ft lab-measured value.

Heterogeneity alone (no physical dispersivity or molecular diffusion) causes no in-situ mixing and cannot explain observed large apparent echo dispersivities. Large apparent echo dispersivities for two reported field tracer tests are shown to result from the effect of drift alone with no dispersion.

The widely reported scale-dependence of apparent dispersivity is a simple and necessary consequence of mis-applying the 1D CD equation, with its single parameter of Peclet number L/α, to conformance it does not describe. Apparent dispersivity is scale-dependent but physical dispersivity is a rock property independent of scale and time.
Maximizing Effective Proppant Permeability under High-Stress, High Gas-Rate Conditions
Authors: Dusterhoft Ron , Nguyen Philip , Conway Mike
Published: December 2007

Work reported in this paper shows that fracture-pack permeability and conductivity are impacted by the mobility of formation-generated fines plugging under high-stress and high gas flow-rate conditions. The authors examine two approaches to (1) prevent formation fines from entering the proppant pack and (2) provide higher sustained fracture-pack permeability and conductivity under severe production conditions. The paper further shows that significant improvements can be obtained in both the short term and the long term, and how these improvements can be used to provide sustained gas production.

The results of laboratory testing are reviewed in detail, including the mechanisms by which fines are immobilized and the conductivity is maintained. The mechanisms involve an on-the-fly, direct coating of proppant with surface- modification agents (SMA) just before the proppant is blended with the carrier fluid. The chemical properties of the SMA can be varied widely to meet downhole conditions and production flow rates. The treatment renders the formation sand and fines immobile so that migration and plugging do not occur. In addition to fines stabilization, SMA can be formulated using liquid resin to consolidate the proppant pack, making it useful in controlling proppant flowback at high production rates, and in providing long-term pack stability. The effects of non-darcy flow are also examined and compared to baseline data.

Field studies are reviewed to evaluate how actual productivity can be affected, both short-term and long-term, by controlling fines damage to provide long-term fracture conductivity.
Multicomponent Processing and Fracture Characterization Analysis at Pinedale Field and Washakie Basin, Wyoming
Authors: Gaiser James E. , Van Dok Richard R.
Published: December 2007

Multicomponent 3-D surveys provide a practical means for analyzing fracture properties where downgoing compressional (P) waves convert to upgoing shear (S) waves at interfaces. The unique characteristics of S-wave azimuthal anisotropy induced by vertical fracturing may provide valuable information for delineating naturally fractured reservoirs and monitoring production performance. In the presence of fractured media, S-waves split into a fast wave that is polarized parallel to fractures and a slow wave that is polarized normal to fractures. The amount of splitting (time difference between the two S-waves) is proportional to fracture intensities. To investigate this phenomenon, we utilize a wide range of source-receiver azimuths in the processing and analyze the fast and slow S-waves to extract fracture information.

Two 3D three-component (one vertical and two horizontal geophones) surveys from Wyoming are presented: one acquired over the southern tip of the Pinedale Field in the Antelope area and the other in the Washakie Basin. The targets are naturally fractured gas sand reservoirs. From the analysis of fast and slow S-waves, the same regional direction of anisotropy was observed in both areas. Layer-based analyses measured anisotropy in the overburden, which required compensation during the processing to isolate the variations at reservoir depths. Eight limited-azimuth volumes were created for the two horizontal geophone components. These volumes were analyzed to determine the time-variant anisotropy within the surveys and the volumes indicated areas of increased fracturing in the overburden as well as at target levels.
Practical Optimization: Working with the Realities of Decision Management
Authors: Haskett William , Better Marco , April Jay
Published: December 2007

Portfolio management tools are designed to aid senior management in the development and analysis of portfolio strategies, however, most of the commercial portfolio optimization packages are relatively inflexible. Most are not able to answer the key questions posed by senior management. Additionally, most senior managers are unfamiliar with the power and advantages provided by a true comprehensive portfolio tool. In order for management to make decisions and to set strategic objectives, these portfolio tools must first provide practical, goal oriented output. This output must be applicable and directly pertinent to the decisions and issues faced by company. The output must provide information that allows decisions to be made that take into account optimization of all scarce resources in the context of the evolving longer-term portfolio.

Practical portfolio optimization requires the efficient spending of all scarce resources: Capital, Time, and Human Resources. A real data set is used to show the results of different ranking and optimization methods, from Markowitz to Meta-heuristics, for a portfolio having prospects at various stages of maturity. The prospects transition along a development path from "pre-identified lead" stage to "targeted effort" stage and then on to "capital allocated" stage where they prove success and capture value. It is vital that this evolution of prospects be captured in any optimization method.

The example portfolio includes optimization of technical and business development personnel. The inclusion of personnel cycle time (varied by functional area), spin-up, and skill set development enables optimal human resource management within the context of longer-term strategy implementation and risk balanced value maximization. Disconnecting the time dependent prospect generation and acquisition activities from the optimal portfolio composition may provide the optimal mix now at the expense of the future prospect development cycle. The preferred optimization methodology must be able to handle strategic business search activities as a portion of the portfolio even though these activities are seldom rigorously quantifiable.
Frequency Dispersion Effects on LWD Shear Sonic Measurements in Acoustically Slow Environments
Authors: Haugland S. Mark
Published: December 2007

This paper presents a study of the sensitivity of LWD shear velocity estimates in acoustically slow environments to the parameters that govern the dispersive borehole-guided waves from which the shear slowness is estimated. This type of analysis is useful for assessing the relative importance of various algorithm parameters and to bound the accuracy of an LWD slow shear wave log given bounds on the accuracy of the parameters associated with the dispersion correction algorithm.

It is assumed that the slowness of a given borehole-guided wave is known. Any errors in the associated shear slowness estimate are ascribed to uncertainty in the parameters that govern the slowness of the borehole-guided wave, and are not associated with individual logging devices and waveform processing algorithms. The possibility that a mode is misregistered is also considered by examining shear slowness errors that result from processing a given mode under the assumption that it is a different mode. This issue seems to be acknowledged in the literature, where some LWD sonic devices have been characterized by terms such as "pseudo-dipole" and "pseudo-monopole."

The analysis is based on a new analytical forward model suitable for calculating the dispersion of borehole-guided waves such as Stoneley, flexural, and screw waves even in the presence of an eccentered metallic mandrel. When the mandrel is eccentered, the flexural and screw modes each split into two unique modes. One mode is referred to as a fast mode and the other is referred to as a slow mode.

Over the parameter range considered in this paper, the fast flexural mode and both of the screw modes appear to be superior to the slow flexural and Stoneley mode when the mandrel is eccentered.
Dual-Energy CT-Scanning Applications in Rock Characterization
Authors: Siddiqui Shameem , Khamees Aon A.
Published: December 2007

The use of dual-energy CT-scanning for evaluating reservoir rocks is not a new technique. It involves scanning the same location within the rock twice, using a different X-ray energy each time. Wellington and Vinegar, in a 1987 paper stated that one image proportional only to bulk density and another proportional to atomic number can be obtained by scanning the sample at high (above 100 kV, Compton scattering dominant) and low (well below 100 kV, Photoelectric absorption dominant) X-ray energies. They generated CT slices showing density and atomic number variations. Although dual-energy scanning has been used quite successfully in fluid flow visualization studies, especially in the case of three-phase flow, its use has been limited in the field of petrophysical core characterization. Part of the problem is due to the unavailability of appropriate software and procedures to generate the bulk density and atomic number images from the high and low-energy CT data and part is due to the lack of necessary steps to utilize the density and atomic number data to characterize the cores. Commercially available software can now allow generating the density and atomic number images from the dual-energy data. This paper describes some techniques to utilize the density and atomic number data to better characterize the reservoir rocks. This technique was first applied to small plug samples of known petrophysical properties for validation purposes. After that, it was applied to a 60 ft-long section of preserved core from an Upper Jurassic carbonate reservoir in Saudi Arabia, which was CT-scanned at two different X-ray energies at 5 cm (2 inch) intervals. Interesting qualitative results were obtained that can improve our understanding of the carbonates. This paper also shows step-by-step instructions for calculating porosity values from the approximate mineral compositions.
The Significance of Non-Darcy and Multiphase Flow Effects in High-Rate, Frac-Pack Gas Completions
Authors: Lolon E. P. , Chipperfield S. T. , McVay D. A. , Schubarth S. K.
Published: December 2007

Hydraulic fracturing combined with gravel packing in high-permeability gas reservoirs (frac-packing, or F&P) is currently considered the most reliable completion technology for offshore Gulf of Mexico (GoM) completions. Such treatments are designed to bypass damage near the wellbore and prevent formation sand production. Despite the relative maturity of this technology, there has been insufficient focus on non-Darcy flow, particularly in the fracture, in F&P wells in the literature.

Previously published work, based on single-phase inflow equations, acknowledged that a very high pressure drop exists near the wellbore in F&P completions, but this has been usually attributed to a limited number of effective perforations. In this work, we used reservoir simulation and an inflow equation for pressure drop across the perforation tunnels to quantify the relative pressure drop contributions in the reservoir, fracture, and gravel pack system. We considered both non-Darcy and multiphase flow in our evaluation.

We found that non-Darcy flow in the fracture and perforation tunnels results in substantial near-wellbore pressure drops for typical F&P gas wells with gas rates greater than 0.2 to 3 MMscf/D/ft. Increasing fracture conductivity and fracture lengths and using proppants with lower non-Darcy flow coefficients can help in reducing non-Darcy pressure drops and optimizing F&P completions.
Deepwater DST Planning and Operations From a DP Vessel
Authors: Stomp Robert J. , Fraser Graham J. , Actis Stephen C. , Eaton Luke F. , Freedman Kerry C.
Published: December 2007

ConocoPhillips (COPC) is developing the Magnolia field with a Tension Leg Platform (TLP) in 4674 feet of water at Garden Banks (GB) block 783 in the Gulf of Mexico (GOM). The field was discovered in 1999 and appraisal wells were drilled in 2000 and 2001. Field development approval was obtained in 2001. The approved depletion plan and well construction strategy included drilling and casing wells prior to the installation of the TLP (pre-drilling), pre-completing and testing one well during the pre-drilling program, and completing the remaining wells from a completion rig installed on the TLP.

The GB783 A2ST3BP1 well was successfully drill-stem tested (DST) from the Ensco 7500 dynamically positioned (DP) semi-submersible drilling vessel in June 2003 as part of the Magnolia field development. The pre-completion and DST operations overcame a number of challenges which included the frac-packing of a thick, fine-grained interval, and well testing from a DP semi-submersible drilling rig while simultaneously transferring produced hydrocarbons to a transportation barge moored to the rig.

The objectives of the pre-completion/DST were to plan and execute the operations safely, validate the sand control design, determine well performance and reservoir properties, and verify the effectiveness of the completion procedures prior to the TLP rig completion program.

This paper will focus on the extensive planning process and the operational aspects of performing a DST in a deepwater environment.
An Experimental and Numerical Investigation of Crossflow Effects in Two-Phase Displacements
Authors: Cinar Y. , Jessen K. , Berenblyum R. , Juanes R. , Orr F. M.
Published: December 2007

In this paper we present flow visualization experiments and numerical simulations that demonstrate the combined effects of viscous and capillary forces and gravity segregation on crossflow that occurs in two-phase displacements in layered porous media.

We report results of a series of immiscible flooding experiments in two-dimensional, two-layered glass bead models. Favorable mobility ratio imbibition and unfavorable mobility ratio drainage experiments were performed. We used preequilibrated immiscible phases from a ternary isooctaneisopropanol- water system, which allowed control of the interfacial tension (IFT) by varying the isopropanol concentration. The experiments performed had a wide range of capillary and gravity numbers. The experimental results illustrate the transitions from flow dominated by capillary pressure at high IFT to flow dominated by gravity and viscous forces at low IFT. The experiments also illustrate the complex interplay of capillary, gravity, and viscous forces that controls crossflow. The experimental results confirm that the transition ranges of scaling groups suggested by Zhou et al.7 are reasonable.

We report also results of simulations of the displacement experiments by two different numerical techniques: finite difference and streamline methods. The numerical simulation results agreed well with experimental observations when gravity and viscous forces were most important and less well for capillary-dominated flows.
Quantification of Hydrocarbon Saturation in Carbonate Formations Using Simultaneous Inversion of Multiple NMR Echo Trains
Authors: Fang Sheng , Chen Songhua , Tauk Raj , Fornage Philippe , Georgi Dan
Published: December 2007

Simultaneous inversion of multiple echo trains (SIMET) is a technique for processing and interpreting Nuclear Magnetic Resonance (NMR) log data that exhibit relaxation, polarization, and/or diffusion contrasts. SIMET is a forward-modeling-based inversion technique that utilizes known correlations between NMR responses and fluid properties, thereby reducing the parameter space dimensions and consequently improving fluid volumetrics and saturation estimates. It is robust when relaxation, polarization, and diffusion contrasts between the fluids are large. However, it is more challenging when the contrasts are small or only a limited amount of different TE (inter-echo time) and/or TW (wait-time) data is available. In such cases, it is especially critical to consider secondary effects, such as those attributable to restricted diffusion or internal gradients. Such information can be added as a prior constraint. An NMR log example is used to illustrate the necessity of correcting for the restricted diffusion effect so that correct oil and water intrinsic relaxation time distributions can be derived, which is the key to the improvement in the final interpretation. For the example, the fluid saturations and viscosity estimated with the SIMET processing are confirmed by the production data.
Determination of Arps' Decline Exponent From Gas Reservoir Properties, and the Efficacy of Arps' Equation in Forecasting Single-Layer, Single-Phase Gas Well Decline
Authors: Voelker Joe
Published: December 2007

This paper presents conclusions as to the ability of Arps’ rate-time decline equation1 to predict boundary dominated gas well rate decline. A correlation of Arps equation parameters, to initial and boundary reservoir conditions, is also presented, enabling the equation to be used to forecast gas well production rates, prior to first production.

The conclusions are derived from a numerical study, consisting of 39 radial flow simulations. The simulations predicted rate declines, against constant bottomhole well pressures, in a single-layer, single-phase, bounded, volumetric gas reservoir model.

The 39 simulations include initial reservoir pressures ranging from 1000 to 10000 psia, flowing bottomhole well pressures from 100 to 7500 psia, and gas gravity from 0.56 to 0.8.

The approach is semi-analytical in that the non-linear differential equation that describes the process, is linearized with a function that approximates the change in viscosity-compressibility product in dimensionless time. The function is integrable and thereby directly yields a closed form solution, of which the Arps equation is a particular case.

The coefficients of the function, which are the Arps parameters, as well as coefficients in a generalized form of Arps’ equation, were optimized to generate rate declines that matched those from the simulation models. Correlation to reservoir and well conditions was then constructed.

It is concluded that Arps’ equation adequately predicts constant pressure, gas well rate decline, over the entire range of conditions enumerated above.

It was also found that Arps’ decline exponent is correlated to reservoir, well, and gas properties. The correlation is aided by Carter's Drawdown Parameter,2 and under certain conditions, the Arps decline exponent is a simple linear function of Carter's Drawdown Parameter.

A determination of the decline exponent from initial reservoir and well conditions, allows the field engineer to forecast depletion (boundary dominated) gas well decline rates, for wells producing against constant bottomhole pressure, without historical decline. The closed form equation precludes the need for reservoir simulation, or specialized commercial software.

The procedure for gas well forecasting using these results is demonstrated.
Analysis of Efficient High-Power Fiber Lasers for Well Perforation
Authors: Gahan Brian C. , Batarseh Samih , Sharma Bhargav , Gowelly Sherif
Published: December 2007

According to many in the laser industry, fiber lasers are now a serious alternative to solid-state and carbon dioxide lasers for industrial material-processing applications. Over the past two years, commercially available fiber lasers have increased in power from several watts to kilowatts. They are now capable of efficiently delivering requisite power via fiber optics to targets downhole, and have rapidly evolved into the leading candidate for on-site applications in well construction and completion. When compared to conventional industrial lasers, fiber lasers offer an order of magnitude greater wall plug efficiency, better beam quality, increased mobility due to their considerably smaller footprint, and essentially maintenance-free operations over their lifetime. Their use as an alternative method to conventional explosive charges could reduce or eliminate perforation damage and significantly boost production rates, cumulative production and overall economic returns.

Since 1997, GTI and its research partners have investigated the application of high-power laser energy for well construction and completion. Early qualitative investigations were performed utilizing weapons-grade military "Star Wars" lasers to demonstrate well construction feasibility. A more quantitative approach followed applying early 1990's laser technology to determine the energy required to break various rock lithologies. Beginning in 2003, GTI advanced its downhole perforation application research using the most recent evolution of high-power lasers: a 5.34 kW Ytterbium-doped multiclad fiber laser.

This paper will provide a description of the fiber laser system, experimental procedures and data analysis used for perforation applications on rock samples. Experiments focus on improvements to rock properties and rock removal efficiency targeting a one foot cube of Berea sandstone. Results from this test will also determine that megawatt-class "Star Wars" military lasers are not required to achieve improvements in near- tunnel permeability. High-power fiber lasers represent a recent technological breakthrough upon which a rugged, deployable system for non-explosive wellbore perforations can be based.
The Continuous Circulation System: An Advance in Constant Pressure Drilling
Authors: Jenner J. W. , Elkins H. L. , Springett F. , Lurie P. G. , Wellings J. S.
Published: December 2007

In late July 2003, for the first time since rotary drilling was introduced, a section of hole was drilled without interrupting circulation while new joints of drill pipe were added to the drill string. This was made possible by the use of the Continuous Circulation System (CCS), developed over the previous three years by a Joint Industry Project (JIP) managed by Maris International, funded by six major oil companies (Shell UK, BP, Statoil, BG, Total and ENI), Coupler Development Ltd (CDL) and Varco and supported by the UK's Industry Technology Facilitator (ITF). The field trial of the CCS was carried out on a land well being drilled in Oklahoma, USA. Its success marked the end of the JIP and the commencement of commercial development of the system.

The CCS is a new and enabling technology, the potential benefits of which are: Elimination of negative and positive pressure surges when stopping and starting circulation to make a connectionNo rig downtime to circulate out cuttings to clear the bottom hole assembly before making a connectionImproved drilling fluid managementElimination of kicks on connectionsImproved control of Equivilent Circulation Density (ECD)Reduced Total Connection Time (TCT)Reduced chance of stuck pipe during a connectionNo downtime in HPHT wells to circulate out connection gasReduced wellbore "breathing" or "ballooning"Overall improvement in hole conditionImproved safety around the rig floor

Potential applications of the system are in drilling: Extended reach (ERD) and horizontal wellsHigh Pressure/High Temperature (HPHT) wellsNear or underbalance (UBD) wellsDeepwater wells

The CCS is also a potential contributor in achieving the "One Trip Well", Journal of Petroleum Technology (JPT) May 2004. The concept was presented in the paper "Continuous Circulation Drilling" by L. Ayling at the Offshore Technology Conference in May 2002.