bluuebunny/crossref_metadata_2025 huggingface dataset:
Near-wellbore Alteration and Formation Stress Parameters using Borehole Sonic Data
Authors: Sinha B. , Bratton T. , Cryer J. , Nieting S. , Ugueto G. , Bakulin A. , Hauser M.
Published: December 2007

Highly depleted reservoirs exhibit sharply lower pore pressures and horizontal stress magnitudes than in the overlying shaly formation. Drilling through such depleted reservoirs can cause severe fluid loss and drilling-induced wellbore instability.Accurate and reliable estimates of horizontal stresses can provide early warning of impending drilling problems that may be mitigated by appropriate drilling fluid design and drilling practices. We have developed a new multi-frequency inversion algorithm for the estimation of maximum and minimum horizontal stress magnitudes using cross-dipole dispersions. Borehole sonic data for the case study presented in this paper was acquired by a cross-dipole sonic tool in a deep-water well, offshore Louisiana in the Gulf of Mexico (GOM). The logged interval spans 1000 ft below the casing shoe. In addition, the Modular Dynamic Tester (MDT)1 mini-frac tests were performed at three depths in shale, yielding two minimum horizontal stress magnitudes. The borehole sonic data was suitable for inversion of cross-dipole dispersions at three depths in shale and also at a depth in a highly depleted sand reservoir. There was one depth in shale above the depleted sand where we could estimate the minimum horizontal stress magnitude using both the MDT mini-frac tests and inversion of borehole sonic data.The results of the two techniques are consistent, providing encouragement for further validation of the multi-frequency inversion of cross-dipole dispersions to estimate horizontal stresses. Even though the overburden stress is expected to increase with depth, both the maximum (SHmax) and minimum (Shmin) horizontal stresses obtained from the inversion of borehole sonic data are significantly smaller in the depleted sand than in the overburden shale. However, both the horizontal stress magnitudes increase again in the shale below the depleted sand. Such rapid variations in horizontal stress magnitudes cause large fluctuations in the safe mud weight window. This challenge in drilling through the depleted sand was successfully handled by using special drilling fluid to mitigate seepage losses and differential sticking in the depleted sand and overlying shale.We have also performed Dipole Radial Profiling (DRP) of formation shear slownesses using the measured cross-dipole dispersions at three depths in shale and one in the highly depleted sand. Analysis of radial profiles in the two orthogonal directions indicates plastic yielding or stiffening of rock in the near-wellbore region. While plastic yielding increases the shear slowness, stiffening would reduce the shear slowness.
The Russian Experience in Reserves Submissions to the SEC
Authors: Gochenour D. T.
Published: December 2007

This paper looks at the historical experience of Russian oil companies in converting their reserves standards to those of the SPE or SEC to conform with the requirements of Western investors.The experience has not been a happy one, and has demonstrated some of the pitfalls of how the SEC administers its standards and definitions.It also shows that while the SPE is going down the path of probabilistic reserves definitions, the SEC is promoting an even more arbitrary deterministic and literal rules based approach which is getting farther away from a scientific definition.
Dynamic Modeling of Invasion Damage and Impact on Production in Horizontal Wells
Authors: Suryanarayana P. V. , Wu Z. , Ramalho J. , Himes R.
Published: December 2007

We present a novel approach that combines dynamic reservoir simulations and special core tests to model the extent of invasive damage and its impact on flow-back during production. A radially adaptive 3D "micro" simulator is used to estimate the extent and impact of filtrate invasion on near-wellbore saturation and reservoir pressure.The lateral extent of the model is limited only to the invasive zone, and time-varying reservoir exposure is used to simulate the acts of drilling, tripping, completions and workovers. Extremely fine, core-scale grids are used to capture saturation and pressure in the invasion zone. Special core tests using a specially-designed core holder are conducted on the subject reservoir core.Test results are interpreted to obtain an estimate of end-point relative permeabilities at irreducible saturation, dynamic mud cake effect on filtrate loss, and impact of solids invasion on return permeability. Both overbalanced and underbalanced tests are conducted with different drilling fluids. The tests are used to describe the mud cake effect in the invasion model. The saturation and pressure profiles from this model are then used as initial conditions in a sector-scale simulator with near-wellbore fine-gridding to model flow-back effects.Absolute permeability damage is modeled using the core test results as an incremental and hyperbolically recovering effect during flow-back simulations. A near-wellbore fine grid overlay is used to capture the near wellbore effects from the micro-simulator results. Several sensitivities, including initial reservoir pressure, degree of overbalance (during drilling) and drawdown (during production), heterogeneity, anisotropy, and mud cake effect are examined.Equivalent skin factors that vary with time and depth are developed to enable comparison with full-field simulations. A horizontal well example is used to illustrate the results of the study. Results illustrate stark and often under-appreciated effects of invasive damage on flow-back and therefore on production performance. The methods described in this work can be used in reservoir-specific studies to model formation damage and aid in the selection of mud types, drilling techniques and remediation methods required to improve performance. It is hoped that this work bridges the typically empirical damage characterization methods with dynamic reservoir simulations.
The Dry Coal Anomaly – The Horseshoe Canyon Formation of Alberta, Canada
Authors: Hoch O.
Published: December 2007

The Horseshoe Canyon coal formation in Alberta, Canada is an anomaly for coals. It is dry, for the most part producing no formation water. Therefore, no dewatering is required. In fact, it is severely damaged by water influx. Normal permeability injection tests and conventional hydraulic fracturing techniques, even foams, have been unsuccessful in this environment. The best part of this reservoir has an areal extent in excess of 12,000 square miles containing 1-2 BCF per square mile of recoverable gas. Commercial development of this resource is a very appealing prospect.

Numbers of coal seams vary from 5 to 30 per well, spread out over 600 – 1,300 ft. Individual seam thicknesses vary from 1 to 13 ft. Most seams are discontinuous over a large area. The better part of the formation has permeability in the range of 1 – 100 md. This makes it difficult to avoid damaging the formation during drilling and cementing operations, hence some type of stimulation is required.

Nitrogen hydraulic fracturing is the only stimulation process that has had any success in this formation to date. The treatments involve pumping nitrogen at high rates, without proppant, through coiled tubing (CT) and a selective cup-type packer (SCP), isolating each coal seam while treating it. Bottomhole treating gradients vary greatly with an average of approximately 2.2 psi/ft.

Whether these nitrogen treatments are in fact fracturing the formation or just having the damage flushed out has been a matter for speculation. Over 1,600 wells have been treated in this way and more continue to be added on an everyday basis.

This paper describes the formation characteristics and geology of the Horseshoe Canyon coal and presents case histories of hydraulic fracturing treatments performed including production results.
Dynamic Petrophysics-Applications of Time-Lapse Reservoir Monitoring in Saudi Arabia
Authors: Ma S. M. , Al-Hajari A. A. , Kelder O. , Al-Muthana A. S. , Srivastava A. , Ramamoorthy R.
Published: December 2007

In reservoir management, accurately measuring remaining oil saturation and monitoring its change with time are conducted with time-lapse reservoir monitoring, including production logs and reservoir saturation logs.Interpreting these reservoir-monitoring logs requires advanced knowledge of multi-disciplines in petroleum engineering.Formation evaluation is dynamic, and data integration is a critical step of the evaluation.Dynamic petrophysics provides the basis for engineers to make critical reservoir-management decisions, such as water shut-off.

In this paper, examples of time-lapse reservoir monitoring are shown to demonstrate the concept of dynamic petrophysics for a well, from initial openhole formation evaluation to intermittent and late-stage, time-lapse reservoir monitoring.All reservoir-monitoring logs were run through production tubing and logged across openhole or casedhole reservoir intervals. Formation water salinity, mixed with different injected waters, was characterized with bottomhole and surface samples.Resistivity logs were interpreted considering both drainage and imbibition petrophysics.Resistivity and carbon-oxygen logs were integrated to provide final oil saturation. Results of this study show that residual oil in water-swept intervals is very low, indicating excellent sweep.

In summary, dynamic petrophysics, based on time-lapse reservoir monitoring, is the basis of reservoir management. Integration of petrophysical, geological, reservoir, and production data is the key to successful dynamic reservoir diagnostics.
Predicting Pump-Out Volume and Time Based on Sensitivity Analysis for an Efficient Sampling Operation: Prejob Modeling Through a Near-Wellbore Simulator
Authors: McCalmont S. , Onu C. , Wu J. , Kiome P. , Sheng J. J. , Adegbola F. , Rajasingham R. , Lee J.
Published: December 2007

Recently, advanced wireline formation testers are being utilized to obtain clean formation samples more often than in the past. Because obtaining clean samples requires a long pumping operation, knowing the required pump-out volume and time for the given formation condition is very important for an efficient and safe operation. This paper shows an application of a new near wellbore simulator to prejob modeling of sampling jobs to assist selecting sampling depth, pumping rate, and minimum-required time and volume to reach a target contamination level.

Advanced formation testers are equipped with sensors that can distinguish the formation hydrocarbon from mud filtrate. The operation may require extended pumping, which may cause problems like tool sticking, mud weight control, inefficient or prohibitive pumping time, or a slim possibility of good samples due to deep invasion. These problems are more pronounced in deep, extended reach wells offshore where rig costs are high. Therefore, careful planning is required to obtain clean formation samples, either hydrocarbon or water. It is especially important for sampling of formation oil when oil-based mud or synthetic mud is used.

To facilitate optimum sampling operations, a newly developed near wellbore simulator is applied for a prejob modeling sensitivity analysis. The simulator is based on a black oil reservoir simulator and can handle a three dimensional, multi-phase flow in the near-wellbore area by incorporating wellbore and formation tester tool factors. Under the given formation parameters of porosity, capillary pressure, and relative permeability, the effects of permeability, anisotropy, formation thickness, pumping rate, probe depth relative to the formation thickness, and invasion depth are investigated.

Field application results for a gas condensate sampling and a formation water sampling are presented in the paper. The pump-out volume and time under various formation conditions to reach a 5- percent contamination level were estimated during the prejob planning stage, and a near infrared spectrometer sensor was used for fluid identification in the actual pumping operation. The prejob modeling results match very well with the sensor responses and the laboratory analysis results further confirm the excellent sample quality with very low contamination. The success of the sampling operation demonstrated the benefits and importance of the well planned, prejob modeling work.
Influx of Advanced Drilling Technologies Maximizing Productivity of Mature Region
Authors: Simonton S. , Seigrist L. , Huizenga Robert , Janwadkar S. , Isbell M.
Published: December 2007

Economical development of oil and gas reserves in Kiowa and Washita counties of Southwestern Oklahoma requires drilling complex structural features with faulted formations and highly dipping beds.To address these challenges, many operators employ packed hole and/or conventional directional motor assemblies to keep inclination to a minimum drilling the production section.While this type of bottom hole assembly has improved directional control, in many cases it still leads to unacceptable angle building tendencies (ie bit walk) and high dogleg severity.This type of BHA has also led to poor vertical hole quality resulting in additional directional issues in subsequent hole sections.In addition, the conventional directional assembly increases well costs due to multiple deviation correction runs with different BHA configurations resulting in more flat time, lower cumulative bit penetration rate, and more bits/runs per hole section.

To reduce drilling costs and maximize production in the region, a service company conducted a detailed analysis of drilling performance, mud logs and wireline data from offset wells. The in-depth study helped engineers identify key problems limiting drilling performance.This led the operator to set new objectives for the production hole section of achieving the highest possible rate of penetration while maintaining a near-vertical wellbore.An implementation strategy was outlined that had two main components including a vertical deviation control system and new PDC bit technology.

This strategy has been implemented to drill 17 wells with excellent results (Operator had previously drilled over 55 wells in the area with the old BHA).The new BHA combination has minimized directional deviation (inclination) and reduced dogleg severity.It has also reduced torque and drag helping deliver a smooth, high quality wellbore and has totally eliminated costly correction runs and increased efficiency and quality of cementing operations.This has allowed the operator to log and set tubulars without incident.
Application of a New Grain-Based Reconstruction Algorithm to Microtomography Images for Quantitative Characterization and Flow Modeling
Authors: Thompson K. E. , Willson C. S. , White C. D. , Nyman S. , Bhattacharya J. , Reed A. H.
Published: December 2007

X-ray computed microtomography (XMT) is used for high-resolution, non-destructive imaging and has been applied successfully to geologic media. Despite the potential of XMT to aid in formation evaluation, currently it is used mostly as a research tool. One factor preventing more widespread application of XMT technology is limited accessibility to microtomography beamlines. Another factor is that computational tools for quantitative image analysis have not kept pace with the imaging technology itself.

In this paper, we present a new grain-based algorithm used for computer reconstruction and analysis of granular materials (e.g., consolidated or unconsolidated sands) and subsequent network generation. The algorithm differs significantly from other methods because the first step is to extract the fundamental granular structure from a 3D data set, which provides a wealth of information such as grain sizes, aspect ratios, orientations, surface areas, etc. Knowledge of the basic granular structure serves as a foundation for characterizing the void morphology and creating physically representative pore networks. The algorithm is applied to a sample of sandstone from the Frontier Formation in Wyoming, USA, which was imaged using synchrotron XMT. Morphologic and flow-modeling results are presented.
Network Modeling of Drainage and Imbibition in Microfractured Porous Media
Authors: Wilson R. , Rodríguez F.
Published: December 2007

This paper investigates two-phase flow in microfractured porous media. We obtain relative permeabilities and capillary pressure curves for drainage and imbibition processes using a two-dimensional microfracture network model. The system of microfractures is composed of interconnected parallel plates of varying apertures, lengths and pre-established orientation.

Fluid flow in each microfracture unit is described by the paralle plate flow model. Capillary pressure for individual microfractures is obtained as a function of fracture aperture. The model takes into account capillary and viscous forces, thus the model allows for the analysis of different configurations of fluids on the network obtained with different capillary numbers and viscosity ratio. Relative permeabilities and capillary pressures are obtained as a function of the average saturation of the fluids in the network and the effect of different flow conditions on these curves is presented.
Enhanced Oil Recovery in Malaysia: Making It a Reality (Part II)
Authors: Samsudin Y. , Darman N. , Husain D. , Hamdan M. K.
Published: December 2007

This paper is an update to an earlier submission1 and presents the current status and progress of several main EOR projects in Malaysia.

As of January 2005, the estimated oil-in-place from producing fields in Malaysia stands at about 17.0 Bstb2, with estimated ultimate recovery (EUR) of 5.62 Bstb. This translates to an averaged recovery factor of only 33.0 percent for producing fields in Malaysia. PETRONAS had realized the importance to further increase the recovery factor and so far has been pursuing EOR implementation in its fields aggressively. To date, a full-field WAG application in Dulang field3,4 is already at its final stages of implementation. In addition, EOR projects have also been planned for another ten fields i.e. Tabu, Tapis, Guntong, Tiong/Kepong and Angsi in Peninsular Malaysia and Baronia, West Lutong, St. Joseph, Bokor and Baram in East Malaysia.

Each of the project is currently at different level of maturity and some preliminary results for five selected EOR projects that are in the late stages of study or in the pilot phase; namely in Dulang3,4, Tabu, Baronia, West Lutong5 and Tapis6 fields will be discussed in this paper.
A New Approach for Continuous Gas Lift Simulation and Optimization
Authors: Vázquez-Román R. , Palafox-Hernández P.
Published: December 2007

Abstracts

Continuous gas lift is one of the most typical forms of artificial lift in oil production. Gas lift is rather inexpensive, easy to implement, very effective in a wide range of operating conditions and requires less maintenance in comparison to other alternatives. The basic principle consists on decreasing the pressure gradient in the liquid via the injected gas. The resulting mixture becomes less heavy than the original oil so that it eventually starts flowing. Current gas lift analytical methods applied to individual wells have applied the state of the art on numerical algorithms such as optimization via genetic or polytope algorithms. However, the models have been oversimplified so that several thermodynamic properties are considered constants though mechanistic basis are often employed.

This paper develops a model based on mass, energy and momentum balances to produce a set of differential algebraic equations (DAEs). Cubic equations of state are used to solve the phase equilibrium behavior and to estimate other required thermodynamic properties. The problems solved include a) Determination of the outlet conditions, at the surface, when the amount of gas and oil production are fixed and b) Determination of the appropriate amount of gas required to lift the oil but matching the outlet pressure at surface manifold. The DASSL package is used to solve the DAEs problem and KNITRO is used to solve the overall optimization problem. The model allows determination of phase behavior along the well according to the automatic integration step produced within DASSL.
Effects of Pour-Point Depressants on Indian Crude Oils
Authors: Kulkarni M. M. , Iyer K.
Published: December 2007

In light of the increasing growth of subsea pipelines, due to increased offshore activity, along with the development of onshore multi-product pipelines in India, the use of chemical additives to decrease wax depositions during transport is becoming increasingly important.

Literature on the rheological behavior of Indian crude oils is sparse. Hence, rheological characterization of crude oils from eight major producing fields was conducted using two commercial pour point depressants (PPD) obtained from Thermax. Crude samples were obtained from the eastern (Oil-A, Rudrasagar) and western (Gandhar, South Kadi, Kosamba and Ankleshwar) parts of the country of which three crude oils (Mumbai High South, Krishna-Godavari Composite, and Enron (Panna and Mukta)) were from the offshore fields. Crude oil assays were also performed on all these oils to determine the wax and asphaltene contents. Rheological characteristics namely, pour point, plastic viscosity and yield strength; using both the PPD's at various dosages (0, 250, 500, 1000 and 2000 ppm) were studied to determine the optimum as well as economic dosage to conform to regulatory requirements.

Results of this study will be presented to show that the pour point has an approximately linear relation up to moderate (~ 25%) wax contents. The asphaltene content does not appear to influence this trend at low concentrations (< 0.34%). Exceptions to these trends were observed in two samples (Kadi and Rudrasagar); where the higher concentrations of other components like resins and napthenes result in exceptionally high pour points. The effectiveness of PPD's shows similar dependence on wax and asphaltene contents, and the PPD's polymeric structures. This study of the fundamental behavior of eight Indian crude oils has formed the basis of exploring the means of pretreating crude oils for efficient transport in commercial pipelines.
Measurement of Surfactant-Induced Interfacial Interactions at Reservoir Conditions
Authors: Xu W. , Ayirala S. C. , Rao D. N.
Published: December 2007

The effect of surface-active chemicals on oil-water interfacial tension (IFT) and wettability in crude oil-brine-rock systems at reservoir conditions is important in enhanced oil recovery processes. However, most of the experimental studies on IFT and contact angles have been conducted at ambient conditions and using stocktank crude oils. In this study, live and stocktank crude oils have been used at reservoir conditions to make IFT and dynamic contact angle measurements using the Drop Shape Analysis (DSA) and Dual-Drop-Dual-Crystal (DDDC) techniques, respectively. Yates reservoir rock and fluids and two types of surfactants (nonionic and anionic) in varying concentrations have been used at reservoir conditions of 82o F and 700 psi.

The dynamic oil-water IFT was found to be a strong function of oil composition, temperature and showed a slight dependence on pressure. An attempt has been made to explain the dynamic behavior of IFT using a four-stage mechanistic model involving induction, diffusion, kinetic barrier and equilibrium stages. The significant difference observed between the advancing contact angles of live oil (55 °) and stocktank oil (154°) clearly indicates the need to use live oils at reservoir conditions to determine in-situ reservoir wettability. Anionic surfactant altered the weakly water-wet behavior of live oil to strongly oil-wet (165°). It was also able to alter the strong oil-wet behavior of stocktank oil to less oil-wet (<135°). The nonionic surfactant was able to alter water-wet live oil system to intermediate-wet (82°), while it did not affect the strongly oil-wet behavior of stocktank oil system.

The oil-wet behavior observed with the live oil due to the surfactants used indicates the possibility of these surfactants to develop continuous oil-wet paths for potential mixed wettability development. Thus, this study is of practical significance where the surfactant-induced wettability alterations to either intermediate-wet or mixed-wet can result in improved oil recovery through lowering of both capillary and adhesion forces.
Determination of Optimal Window Size in Pressure-Derivative Computation Using Frequency-Domain Constraints
Authors: Cheng Y. , Lee W. J. , McVay D. A.
Published: December 2007

Analysts commonly use the pressure derivative to identify flow regimes and well-test-interpretation models in pressure-transient test analysis. Analysts and commercial analysis software commonly use Bourdet's approach to calculate derivatives from measured pressure data. Bourdet's algorithm includes a weighted central-difference approximation with a certain "window" size based on an increment in the logarithm of time, represented by the symbol L. Although test analysts commonly select L in the range of 0.1 to 0.3 log cycle, no criterion is available for choosing the optimal value of L.An unresolved issue in pressure transient test analysis is how to determine the optimal L based on the data for each individual data set such that the data are smoothed sufficiently to remove noise that obscures the signal but not smoothed to the extent that the signal itself is changed.

This paper presents a new approach to calculate the pressure derivative, and improves the results compared to those we achieved in a previous paper, SPE 84471. This approach determines the optimal window size to use with Bourdet's algorithm by employing the fast Fourier transform, Gaussian filtering, and frequency-domain constraints. Our approach denoises the data in the frequency domain, determines the optimal window size, and, when coupled with Bourdet's algorithm in the time domain using the optimal window size, provides an improved pressure derivative. We also developed a novel adaptive smoothing algorithm by recursive differentiation-integration to further improve pressure derivative calculation. Our method can efficiently suppress measurement errors and produce smooth pressure derivatives from well-test data. Equally important, it can prevent over-smoothing of the data by inappropriate use of large window size, and it can preserve the characteristic behavior of the pressure derivative.

We validate our approach with a synthetic example and demonstrate its applicability to actual field examples.
Automated Process Control System for Steam-Injection Processes
Authors: Shin H. , Alleyne I. , Polikar M.
Published: December 2007

Two types of models have been used when it comes to scaling steam-based injection processes from the laboratory to the field: low pressure and high pressure models. The latter, which uses similar fluids and operating conditions as the field reservoirs, is more suited for the steam injection process.

Conducting high pressure and high temperature model experiments is very difficult as many variables, such as steam quality, injection rate and pressure need to be controlled all at once and in real time.An advanced automated process control system has been commissioned to overcome this operating complexity in steam injection wells. Steam quality is calculated using a neural network. This network uses an intermediate temperature in the heater and its control signal to assess the steam quality leaving the heater. The production cooling system controls the temperature of the produced fluids at 60oC in order to achieve a significant difference in density between the process fluids, water and heavy oil. As the water and oil densities are known at the controlled temperature, the water cut is determined by measuring the combined density of the produced fluids with a coriolis flow meter.This study has shown that an automated process control system is capable of controlling and optimizing steam injection processes like the steam-assisted gravity drainage process.
Application of Fast Fourier Transforms to Deconvolution of Multirate Well Test Data
Authors: Cheng Y. , Lee W. J. , McVay D. A.
Published: December 2007

Deconvolution of pressure and flow rate measurements is one of the great challenges inherent in well test interpretation. Deconvolution allows the test analyst to estimate the constant-rate transient pressure response of a reservoir-well system, and assists us in system identification and parameter estimation. Unfortunately, deconvolution amplifies the noise contained in data. Often we cannot identify the reservoir system from deconvolved results owing to solution instability caused by noise in measured data.

We previously presented1 a deconvolution technique based on the fast Fourier transform that we applied to a single buildup or drawdown period. Unlike other deconvolution methods that deconvolve pressure and rate data in the time domain, our method deconvolves pressure and rate data in the frequency domain. We found that we can remove the noise transferred to deconvolved pressures in the frequency domain, and we can find a stable and interpretable deconvolution solution even when test data are noisy.

In this paper, we extend our previous work and apply the deconvolution technique based on the fast Fourier transform to arbitrarily changing rate profiles such as multi-rate tests. The deconvolution results, which represent a constant-rate pressure drawdown response spanning the entire duration of the test, can provide helpful insight into the correct reservoir description. We have improved our original deconvolution method in number of ways, particularly with the introduction of an iterative algorithm that produces stable deconvolution results. We demonstrate application of our deconvolution method to analysis of synthetic and field examples, including both flow and shut-in periods. Our deconvolution method can efficiently reproduce the characteristic responses of the reservoir-well system and increase our confidence in parameter estimates.
Can "Smart" Well Technology Manage Production from a Compacting Reservoir?
Authors: Elmsallati S. M. , Davies D. R. , Prada M. , Llewellyn B.
Published: December 2007

Reservoir compaction in deep water, unconsolidated, turbidite reservoirs can cause large-scale permeability damage to nearwellbore area, the resulting skin reducing the well productivity. This is due to the depleting reservoir pressure resulting on an increased effective stress on the fabric of the reservoir rock leading to a reduction in both permeability and porosity. Permeability reduction will decrease recovery while porosity reduction will improve recovery by maintaining the fluid pressure & increasing the oil saturation. The interplay of these phenomena was studied using a reservoir simulation model of a typical deepwater, compacting, compartmentalized layered reservoir. Eighteen months production experience was available for history matching. This paper will show how the above understanding can be used to optimize the well performance and explain "unusual" production performance observations e.g. a decreased water cut was predicted if water injection was implemented.

This study reviews the potential value creation through development of a compacting reservoirs using Intelligent Well Technology (IWT) compared to a conventional well development. IWT offers great flexibility to monitor, operate and control production at the Zone and Reservoir level. This led us to examine whether the draw down around the wellbore could be optimized so that permeability damage is minimized as a means of increasing recovery in compacting reservoirs.

This paper shows how evaluation of I-well value generation has to combine the traditional reservoir engineering studies of well location and pressure maintenance while simultaneously optimizing the details of the well completion design and the newer technologies associated with managing compacting reservoirs. A doubling of the field reserves was predicted by completing the new well with IWT. IWT also effectively managed non-optimum situations e.g. placement of the well in the incorrect location.
Downhole Pressure Boosting in Natural Gas Wells: Well Candidate Selection and Project Progress
Authors: Liley J. A. N.
Published: December 2007

In recent years gas E&P companies have acknowledged that pressure boosting in close proximity to a reservoir can accelerate production rates as well as increase the recovery of reserves beyond that possible by conventional central compression alone.This paper summarises the key well and reservoir parameters that determine the production enhancement potential of downhole gas compression (DGC).

An industry funded JIP has been established to complete the development of this key enabling technology. Detailed design is well underway with the objective of completing a field trial in 2007.A summary of progress to date on this project is included in this paper.
Developing Calibrated Fracture Growth Models for Various Formations and Regions Across the United States
Authors: Weijers L. , Wright C. , Mayerhofer M. , Cipolla C.
Published: December 2007

Utilization of direct fracture mapping technologies has greatly increased over the last few years, from the first real-time measurement of fracture dimensions in 1997 to the routine mapping of fracture dimensions on more than 500 fracture treatments per year in 2004.The development of commercial technologies1-5 to routinely measure fracture growth has greatly improved our fracture modeling capabilities, enabling us to distill the essential fracture growth behavior in many environments into calibrated fracture models.

Calibrated fracture models combine complimentary strengths and weaknesses of fracture mapping and modeling.Fracture models provide the ability to predict how changes to a fracture treatment should alter fracture geometry6, but suffer from a tenuous and generally unknown relationship with reality.Fracture mapping provides a direct measurement of fracture geometry from a given treatment, but cannot be used to predict what might happen under a different set of conditions.By combining direct measurements with models, we can create calibrated frac models with superior predictive capabilities.

Calibrated models have been developed for various regions and formations, and the improvements in predictive modeling capabilities have lead to a proliferation of calibrated fracture models throughout the industry.This has provided improved insight into fracture growth behavior in a diverse set of environments including the North Texas Bossier and Barnett shale, the East Texas Cotton Valley sands, and various formations in the Rockies, the San Juan basin and California.

This paper discusses how fracture growth models can be improved using direct fracture geometry measurements and what changes in models have been necessary to accomplish this.We will also discuss minimum data requirements for calibrated models, discuss their main limitations and capabilities, and the strategies that are used to define calibrated models.Finally, we will present several case histories – comprising the results of over a hundred mapped treatments – to illustrate how these findings have been used to improve fracture treatment design, execution and economics in various formations and regions across the United States.
Development and Use of a Cost-Effective, Low-Density Cementing System for Reducing Equivalent Circulating Densities (ECDs) and Obtaining Improved Pipe/Cement/Formation Bonding
Authors: Fyten G. , Luke K. , Quinton C. , Griffith J. E.
Published: December 2007

Cementing wells drilled through weak formations can result in lost-circulation problems.The industry typically uses high-cost, low-density cementing solutions that include the use of hollow beads or nitrogen. In other cases, stage cementing may be employed, which could also raise the overall well cost. A new, non-nitrified cement system using cost-effective, non-traditional cementing materials has been developed that can provide adequate placement and set properties.Emphasis during development of this system was to provide low-density, low-viscosity slurries that would result in the lowest equivalent circulating densities (ECD) possible while maintaining sufficient set properties.

This paper provides information on performance characteristics of the new cementing systems critical to providing effective cementing solutions, including compressive- strength development, flow properties, thickening times, and expansion properties.

Case histories presented show how use of the system resulted in significant savings in cementing cost in wells that required reduced ECD.
Tubing Buckling—The Rest of the Story
Authors: Mitchell R. F.
Published: December 2007

The most fundamental question about helically buckled pipe is "What is the pitch?" The original development by Lubinski and Woods used the method of virtual work to determine a specific constant pitch. All attempts to connect a constant pitch helix to boundary conditions, such as a packer, have failed. The conventional wisdom says that the virtual work solution applies "far from the packer". How "far" is this, and what happens between the packer and this point? Even worse is the case of tapered strings. The generally accepted answer to the tapered string problem is a "stacked" set of Lubinski solutions, with each solution "far" from the interconnection of the different sized tubulars.

Perhaps there are non-constant pitch solutions? Since the buckling differential equation is non-linear, it is not surprising that no other analytic solutions have been discovered until recently. Once these solutions are known, the initial value problem can be posed and solved. Two possible boundary conditions are considered in this study: a cantilever boundary condition to model a packer, and a "pinned" boundary condition to model a centralizer. For the first time, analytic solutions were found for both problems, and interestingly, both solutions converged rapidly to Lubinski's constant pitch solution at a specified distance from the boundary. For this reason, many of the original Lubinski calculations remain essentially correct, such as length change and contact forces. On the other hand, the bending moment near the boundary exceeds the bending moment calculated from the Lubinski solution by as much as 20%. For this reason alone, conventional pipe buckling stress analysis must be revised. Further applications of these solutions allow different sized tubulars to be interconnected, solving the tapered string problem for the first time. An additional useful result is the solution to the helix "reversal" problem.

The principal applications for these solutions are the stress analysis and design of tubing and casing strings. The boundary solutions are simple formulas, suitable for spreadsheet or hand calculations.
How Aphron Drilling Fluids Work
Authors: Belkin A. , Irving M. , O'Connor R. , Fosdick M. , Hoff T. , Growcock F. B.
Published: December 2007

Aphron drilling fluids, which are highly shear-thinning water-based fluids containing stabilized air-filled bubbles (aphrons), have been applied successfully worldwide to drill depleted reservoirs and other high-permeability formations. Although the performance of these fluids in the field is well documented, questions remain about how such fluids work. A study was initiated this past year under the auspices of the U.S. Department of Energy to develop some understanding of the mechanisms by which these fluids can seal loss zones with little permanent formation damage.

Among the key findings of this on-going project is that aphrons can survive elevated pressures for a much longer time than conventional bubbles, though they appear to be fairly sensitive to shear. In a loss zone, aphrons that survive the trip downhole can migrate faster than the base liquid and concentrate at the fluid front, thereby building an internal seal in the pore network of the rock. A microgel network formed by particulates in the drilling fluid aids the aphrons in slowing the rate of invasion, as does, of course, the radial flow pattern of the invasion. As the fluid slows, the very high LSRV (low-shear-rate viscosity) of the base fluid becomes increasingly important; this high LSRV, coupled with low thixotropy, enables the fluid to generate high viscosity rapidly. Bridging and formation of a low-permeability external filter cake also occur during the latter part of this period, ultimately reducing the rate of invasion to that of ordinary fluid loss.

Another key finding is that aphrons have very little attraction for each other or for mineral surfaces. Consequently, they do not readily coalesce nor do they stick easily to the pore walls, resulting in easy displacement by the produced fluids. In addition, the drilling fluid itself is very compatible with produced fluids and generates low capillary forces, thereby facilitating back-flow of produced fluids. The combination of these two effects is expected to result in low formation damage and minimal requirements for cleanup.
A Laboratory Study of the Effect of Installation of Reticulated Expandable Liners on Sand Production in Weakly Consolidated Sandstone Formations
Authors: Nouri A. , Vaziri H. , Kuru E. , Islam R.
Published: December 2007

Using novel physical model experiments involving large size sandstone specimens, an investigation was conducted on the effect of reticulated expandable liners with various perforation sizes on the rate of sand production.

A series of experiments were conducted using Hollow Cylinder Samples (HCS) completed with no internal support and with support using reticulated liners, or stiffener. The main objective of the investigation performed was to observe whether sanding could occur in wellbores supported by stiffeners and if so, what would be the role of the mesh opening size to the grain size on the onset and severity of sanding. Quantification of the effects of supporting the wellbore by the stiffener on wellbore productivity is another objective of the paper.

The experiments on weakly-consolidated sandstones showed that the stiffener is effective in preventing any shear failure around the wellbore. Under excessive drawdown / depletion, however, pore collapse was seen as a potential failure mechanism in the material. Despite this, much less sanding occurred compared to an openhole case and this improvement was attributed to (1) an enhanced grain-to-grain friction resistance due to higher effective stress state at the wellface, and (2) reduced loss of sand face integrity in a state where the material undergoes pore collapse.

Other useful findings include the role of the stiffener on increasing the mean effective stress around the wellbore which in turn reduces the porosity and permeability of the material in that region due to compaction. This is in spite of the fact that dilation due to shear failure can substantially increase the permeability and porosity of the material within the near vicinity of the well opening and perforation tunnels. As a result of material compaction, the overall porosity and permeability of the sample showed a declining trend during the experiments. However, this gradual decline of permeability can be compensated by applying a greater drawdown with little increase of the potential of sanding.

The findings of this study provide a deeper insight into the role of reticulated liners as a cost effective measure for sand control. Such potential applications will be discussed in this paper.
Novel CO2-Emulsified Viscoelastic Surfactant Fracturing Fluid System
Authors: Hall R. , Chen Y. , Pope T. L. , Lee J. C. , Lugibihl S.
Published: December 2007

The solid-free viscoelastic surfactant (VES) fluid has good proppant transport and excellent cleanup capabilities. Coupling the benefits of a VES fluid with a carbon dioxide (CO2)-emulsified system will further enhance cleanup in a depleted reservoir, extend the application to water-sensitive formations, and maintain reservoir gas saturation to prevent any potential water blocks. This paper reports on a new multisurfactant VES fluid system developed specifically to provide a robust surfactant-base fracturing fluid with supercritical CO2. The field test results indicate the new system is CO2 compatible and still possesses all the attributes normally associated with VES systems.
Effect of Fracture Width and Fluid Rheology on Proppant Settling and Retardation: An Experimental Study
Authors: Liu Y. , Sharma M. M.
Published: December 2007

Water-fracs (using slick water instead of gel to transport proppant) have proved to be a successful fracturing technique in some tight gas reservoirs. Proppant placement is an essential factor that determines the effectiveness of such hydraulic fracturing treatments. This paper presents an experimental study conducted to investigate the impact of fracture width and fluid rheology on proppant transport (including particle settling and horizontal transport).

Data is presented to show that the settling velocity is significantly reduced as the fracture width becomes comparable to the proppant diameter. Experimental results are presented for Newtonian fluids with different viscosity as well as shear thinning fluids such as guar gum and Xanthan. Experimental correlations are presented for the proppant settling velocity as a function of the dimensionless fracture width and fluid rheology. These correlations are compared with theoretical predictions based on slot flow models presented earlier. The effect of fracture wall roughness is studied by conducting slot flow experiments on cells with rough walls. Wall roughness is shown to impact the results substantially and a new correlation is presented to account for wall roughness.

Data is presented to show that the proppant usually flows at a lower horizontal velocity than the fluid, particularly in narrow fractures. The proppant is either retarded or accelerated depending on the ratio of the proppant size to the fracture width. It has been found that for a single particle, when this ratio is small, the proppant travels faster than the average fluid velocity at that location because the proppant tends to be confined to the center of the flow channel where the fluid velocity is higher. As the proppant size increases, the effect of the fracture walls becomes more important and the proppant is retarded by the walls. The retardation of particle relative to the fluid is greater for larger particles and greater proximities to the fracture walls due to the hydrodynamic stress exerted on the sphere by the walls in the narrow gap. Data and correlations are presented that show this dependence. Proppant retardation is particularly important for shear thinning fluids and when the fracture width becomes comparable to the proppant diameter.