bluuebunny/crossref_metadata_2025 huggingface dataset:
Relative-Permeability Coupled Saturation-Height Models Based on Hydraulic (Flow) Units in a Gas Field
Authors: Amabeoku M. O. , Kersey D. G. , BinNasser R. H. , Belowi A. R.
Published: December 2007

Saturation-height functions based on unique flow units have been developed as part of an integrated petrophysical analysis of a gas field. Furthermore, coupling the saturation functions with appropriate relative permeability models has effectively quantified hydrocarbon saturation, classified producibility of intervals and defined critical water saturation. The results show that linking depositional and diagenetic rock fabric to flow units, and then linking the flow units to zones with similar core capillary pressure and relative permeability relationships, have enhanced the utility of the saturation models. The saturation-height functions provided accurate water saturation, and they can potentially overcome uncertainties associated with log interpretation, using Archie or shaly sand models.

The saturation-height models were developed from core capillary pressure (Pc) data to calculate water saturation versus depth, which is independent of logs. The relative permeability models were obtained from special core analysis (SCAL). Consequently, the core-based saturation height functions can be useful in the calibration of log-based petrophysical models and, via relative permeability, can also be used to estimate water gas ratios and critical water saturation.

Capillary pressure and relative permeability curves from special core analysis studies were distributed into corresponding flow units, based on the calculated flow zone indicators. Saturation-height functions were then developed for each unit and used to calculate water saturation in the study field. The most accurate flow unit-based saturation model that evolved is a function of only porosity and height above free water level, does not require permeability in its application, and performed better than the Leverett J-function in this field.

Coupled with hydraulic unit (HU)-based relative permeability curves, the saturation models will provide more comprehensive petrophysical interpretation in gas bearing formations as well as highlight potential differences in reservoir producibility.
Oil and Gas Fields Offshore Egypt: History and Case Studies
Authors: Ellaithy W. F. , Raheem M. G. A.
Published: December 2007

Egypt is located at the north east of Africa where Gulf of Suez and the South East part of the Mediterranean represent the offshore Egypt. Economical development of oil and gas fields in the Gulf of Suez and the Mediterranean requires to maintain the offshore installation within the cost effective envelop by selecting the appropriate development facilities, performing the construction with minimum interruption of weather down time, and selecting the suitable installation marine spread.

This paper presents studies based on several cases past experience of pipelines installation, offshore structures fabrication and installation and sub sea developments of offshore Egypt. The paper presents the weather conditions profile all year round and demonstrates the good weather conditions in both the Gulf of Suez and in the Mediterranean. Seabed conditions and change in water depth contribute to the final selection of the oil and gas fields development outlines, to the equipment selection for the offshore installation and the support marine spread. Onshore support and maximization of prefabrication in the near by fabrication facilities is another contribution to achieve cost effective development.

This paper presents case studies in pipeline installations, and complex platforms fabrication and installation, as well as sub sea facilities construction. The paper will discuss different approaches for pipeline protection and stabilization. In addition, it presents a comparison for conventional heavy decks offshore installation and sub sea equipment.
Transversely Multifractured Horizontal Wells: A Recipe for Success
Authors: Demarchos A. S. , Porcu M. M. , Economides M. J.
Published: December 2007

While the hydraulic fracturing of vertical wells is perhaps the most widely used method for production/injection enhancement in the petroleum industry, the fracturing of horizontal wells has been used sparsely, mostly in the United States and the North Sea. Usually this involves either longitudinal fractures or treatments with no regard to the well orientation and fracture azimuth.

The systematic transverse fracturing of horizontal wells poses several challenges in design and optimization and in operations and execution. A multi-fracture design and a feasibility study are performed to identify candidates for both a technical and an economic success. We used a fractured vertical well as the basis of our calculations and we have determined the dimensionless PI as the means to evaluate the attractiveness of multiple transverse fractures intersecting a horizontal well.

In previous publications we have presented the Unified Fracture Design and how its adaptation by several companies and researchers led to major new successes. The drainage shape and flow regime in transversely fractured wells differs significantly from vertical wells. The Unified Fracture Design had to be adapted with shape factors to account for the differences. We are showing a series of designs using a range of sizes of fracture volumes, different proppant types and drainage sizes.

For treatment execution, traditional methods of perforating may increase the probability of failure. The types of reservoir which are candidates for these treatments such as multi-layered reservoirs will almost surely affect the fracture initiation, and, as usual, composite materials show higher mechanical resistances compared to homogeneous materials. A new abrasive jet cutting tool has now been designed and built specifically for this type of jobs.

In this paper we will present all the design and operational challenges that will be faced in such fracturing project, and make recommendations for successful treatments
Shear-Type Borehole Wall Shifts Induced During Lost Circulations
Authors: Iwashita D. , Morita N. , Tominaga M.
Published: December 2007

Three typical borehole wall shifts during lost circulations are studied and parameter studies are conducted for evaluating the magnitude of the shifts. Slant-crack induced around vertical wells during lost circulations.Parameters varied are the frac size/wellbore size, frac angle, borehole pressure and σH1,σH2,σV ratio.Borehole wall shifts induced during the drilling of normal, thrust, and strike-slip fault areas.Borehole wall shifts induced for an inclined well due to a fracture induced in perpendicular to the minimum in-situ stress.
Full-Field Parallel Simulation Model: A Unique Tool for Reservoir Management of the Greater Burgan Oil Field
Authors: Ambastha A. K. , Al-Matar D. , Ma E. , Kasischke B.
Published: December 2007

The Greater Burgan field in Kuwait is the largest clastic oil reservoir in the world. Reservoir simulation in this gigantic reservoir presents formidable challenges in any modeling effort. Its sheer size, complex geology, intricate surface facility network, 2,200 completions, and 58-years of production history with significant uncertainty represented a daunting task in history-match and prediction.

The quest began in 2002 with the creation of a 65-million cells’ geostatistical earth model. The full-field simulation model of 1.6-million cells consists of six major oil reservoirs (Wara, Mauddud, 3SU, 3SM, 3SL, and 4S) with 145 faults. These faults are major conduits allowing fluid migration between reservoirs. This paper describes the history-matching process used in detail along with the value that has been added through prediction cases run with this model to date.

A tiered history-matching approach was used based on field, gathering center (GC), GC-sand and key well-level observations. Also, a full-field net oil column thickness map was used for detailed saturation matching over the entire field. Fault parameters, kv/kh, and aquifer connections turned out to be important history-matching parameters in this exercise.

Prediction cases with this model were set up by automatically managing GC-level oil and water handling limits, field-level oil rate targets, facility upgrades, infill drilling schedule, treatment of selective and additional potential wells, and operational criteria for individual well shut-down. Automatic logic to manage all of these features caused a parallel CHEARS (an internal Chevron reservoir simulator) 50-year prediction case run-time to be around 2 days on the 16-CPU IBM Regatta machine using AIX5.1 operating system.

Today, it is regarded as the key corporate planning tool for strategic field development and secondary recovery assessment for the Greater Burgan field. This model has been used for Base case forecasting as well as artificial lift, additional 3SU infill drilling, and Wara pressure maintenance project (PMP) evaluations to date. Procedures used to set up these value-added cases will be discussed.

The systematic process used in this project for history-matching and prediction will be useful for all reservoir simulation exercises on large fields with a very long history.
First Laboratory Perforating Tests in Coal Show Lower-than-Expected Penetration
Authors: Snider P. M. , Walton I. C. , Skinner T. K. , Atwood D. C. , Grove B. M. , Graham C.
Published: December 2007

Worldwide Coal Bed Methane (CBM) resources are huge, estimated at 3,000 to 9,000 Tcf. The worldwide production from CBM is dominated by US production of 1.6 Bcf/year, where an estimated 20,000 wells are in production from CBM reservoirs. Wyoming's Powder River Basin (PRB) alone has 12,000 wells in production, with an estimated 50,000 more wells to be drilled in the next 10-15 years. The production rate from CBM reservoirs is low, perhaps 50-100 mcf/day. Various completion methods are being evaluated and new technologies are being developed with the aim of increasing production rates.

Considering this interest and activity level, there has been very little attention paid to the CBM completion fundamentals. Perforating is a critical part of this process, especially considering the PRB development migration from single-coal open-hole completions into multi-zone cased-hole completions Whereas the industry has substantial knowledge of perforating characteristics in sandstones and, to a lesser extent, carbonates, almost nothing is known about perforating in coal. Predictions of perforation characteristics, such as depth of penetration, are based on correlations developed for sandstones.

This paper will describe the first known laboratory-testing program to investigate shaped charge penetration in coal targets. We will describe mechanical properties of the coals tested, and penetration results for different shaped charges (of different designs), shot at various stress conditions. CT scan and cutaway imaging of the perforation tunnels will also be discussed. Tests were conducted under dry and saturated conditions.

The preliminary experiments reported here indicate that shaped charge penetration in coal is significantly less than expected, considering the target's density and strength. The authors will provide insight into what may be the reasons for these unexpected results and recommend a path forward for shaped charge testing, designs, predictive tools, and how to optimize CBM completions.
Application of Smart, Fractured Water Injection Technology in the Piltun-Astokhskoye Field, Sakhalin Island, Offshore Russia
Authors: van Nispen D. J. , Hunt J. , Hartwijk A. , Trofimov A.
Published: December 2007

This paper discusses the application of new technologies and surveillance requirements with particular reference to fractured waterflood developments, highlighting specific considerations for the Piltun-Astokhskoye field and the harsh and sensitive Far East Russian environment. Early results and lessons learned from fractured water injection in the Astokh area of the field are presented, as well as implications ans plans for the Piltun development.
Theoretical Analysis of Bottom Water Invasion at Oil Wells Due to Transverse Dispersion
Authors: Duan S. , Wojtanowicz A. K.
Published: December 2007

Inaccurate modeling of fluid flow near-wellbores is commonly recognized as shortcoming of numerical reservoir simulators. After water breaks through, the well's inflow involves two or three fluids flowing at velocity exponentially increasing with reducing distance to the well. Understanding of the oil/water inflow to wells and possible improvement of its simulation is the objective of this study.

Current commercial simulators disregard the effect of dispersion due to high flow velocity. They only consider effects of viscous and gravity forces, capillary pressure and sometimes Non-Darcy flow effects. We postulate that a process of transverse immiscible dispersion should be considered in evaluating the oil/water transition zone around a well and the production water cut. Transverse dispersion is a process of mixing two fluids in the direction perpendicular to the segregated flow of two phases. In the process, one phase enters the stream of another phase and contributes to the flow characters and the saturation distribution change. Away from the well where the flow velocity is low, the effect is small and overshadowed by the capillary pressure effect. It, however, may significantly increase as the two-phase flow is approaching well since the transverse dispersion coefficient is a function of velocity. Thus, at the well, transition zone size and distribution might be significantly affected by transverse dispersion resulting in water production larger than results of current simulators.

In this paper, an analytical model of transverse dispersion in porous media is derived and used to study various factors influencing the dispersion. The results show that radial distance and mechanical dispersion coefficient are essential to transverse dispersion. It also shows that transverse dispersion controls transition zone growth at the bottom of well's completion where vertical gradient of horizontal velocity is the largest – up to 0.25 ft/s-ft.
New Results Improve Fracture Cleanup Characterization and Damage Mitigation
Authors: Ayoub J. A. , Hutchins R. D. , Van der Bas F. , Cobianco S. , Emiliani C. N. , Glover M. , Marino S. , Nitters G. , Norman D. , Turk G.
Published: December 2007

It is well documented in the literature that hydraulic fracture treatments, although successful, often underperform: Frac and Pack completions exhibit positive skin values, and traditional hydraulic fracture completions show discrepancies between the placed propped length and the effective production fracture length. Ineffective fracture clean-up is often cited as a likely culprit.

This paper presents some of the results of an investigation of fracture clean-up mechanisms. This investigation was undertaken under a Joint Industry Project (JIP) active since the year 2002. The data discussed builds on the initial results published in early 2006, which indicated that the polymer concentrates only in the filter cake and that flow along the fracture encounters significant yield stress when the filter cake cumulative thickness dominates the width of the fracture.

The new results presented here demonstrate successful strategies that mitigate the effects of excessive filter cake thickness. Experimental data demonstrate that flow along the fracture would encounter lower yield stress when the breaker is delivered directly to the filter cake as opposed to randomly distributed. The data also indicate that a smaller breaker amount delivered directly into the filter cake is more effective at reducing the yield stress effects than a larger breaker amount delivered randomly in the slurry. Alternative breaker materials are explored and additional data are also presented to estimate the yield stress effect for fluid flow across the filter cake from the reservoir into the fracture.
Hydrate Inhibition of Subsea Jumpers During Shut-in
Authors: Cagney T. , Hare S. , Svedeman S. J.
Published: December 2007

Flow assurance plans typically call for flushing subsea well/manifold jumpers with methanol to displace and inhibit any water accumulated in the jumper and to prevent the formation of hydrate blockages during shutdown. This paper presents the results of experiments that were conducted to evaluate the effectiveness of methanol injection and gas purging on removing and inhibiting water in a jumper. Variables in the test program included different water cuts and gas volume fractions in the jumper, the methanol injection rate, gas purge flow rates, oil properties, and the jumper inclination angle.

The tests showed that methanol injection rates, over 88 gpm (20 m3/hr), were required to sweep all of the water out of the 6.0" (15.24 cm) diameter horizontal jumper, but even at lower rates, 22 gpm to 44 gpm (5 m3/hr to 10 m3/hr), large amounts of water were removed. Inclining the jumper at angles from horizontal (up to ±5°) reduced the amount of water remaining in the jumper at the end of a methanol flush. Even at relatively low methanol injection rates, most of the water could be removed from an inclined jumper. Gas purge rates with superficial velocities in excess of 30 ft/sec (9.1 m/sec) were required to sweep all of the water from a horizontal jumper. Inclining the jumper to −5° from horizontal (fluid flowing downhill) significantly increased the amount of liquid removed from the jumper compared to the horizontal orientation.

The test results will be used to determine the design parameters required to prevent hydrate formation in deepwater jumpers. They will help define field requirements for methanol pump size, pump power, umbilical size, methanol storage requirements, and aid in the development of effective hydrate prevention strategies while minimizing platform requirements for space, weight, and power.
Quantifying 3D Land Seismic Reliability and Value
Authors: Bickel J. E. , Gibson R. L. , McVay D. A. , Pickering S. , Waggoner J.
Published: December 2007

Seismic data provide important information for guiding reservoir development. Improvements in data quality hold the promise of improving performance even further. Yet, the value of these data, and decision making capability, must exceed its cost. Previous work has demonstrated value of information (VOI) methods to quantify the value of seismic data. In these examples, seismic accuracy is obtained via expert assessment instead of being based on geophysical quantities. In addition, the modeled seismic information is not representative of a quantity that would be observed in a true processed seismic image. Here we apply a more general VOI model that includes multiple targets, budgetary constraints, and, importantly, quantitative models relating post-stack seismic amplitudes and AVO parameters to the quantities of interest for reservoir characterization, such as porosity and reservoir thickness. In addition, by including estimated changes in data accuracy related to signal-to-noise ratio, the decision model can provide objective estimates of the ability of the seismic data to provide reliable measurements and its value. We demonstrate this methodology within the context of a west Texas 3D land survey. This example demonstrates that seismic information can be quite valuable and improvements in seismic technology can create significant value for E&P companies.
Characterization of a Shallow Horizontal Fracturing Treatment in Western Missouri
Authors: Britt L. K. , Dunn-Norman S. , Smith M. B. , Atekwana E. , Slater L. , Gupta A. , Numbere D. , Fontana J. V. , Viellenave J. H. , Pelger J.
Published: December 2007

Normally, the objective of hydraulic fracturing is to design and execute a fracture treatment that achieves the desired fracture dimensions (length & conductivity) to maximize a wells production rate and reserve recovery. Treatments are most typically applied in reservoirs with in-situ stresses that yield vertical fractures. Case studies of horizontal fractures and identification of the key parameters unique to horizontal fractures are uncommon, in part due to the fact that oil and gas reservoirs occur in relatively deep subsurface formations.

A research project, sponsored by the U.S. Department of Energy, was undertaken to demonstrate a development method for the significant heavy oil reserves that exist at ultra-shallow depth in the Pennsylvanian sands in Southwestern Missouri and Southeastern Kansas. The principal objective is to demonstrate an economically viable and sustainable method of producing the shallow heavy oil using a combination of microbial enhanced oil recovery (MEOR) treatments and horizontal fracturing in vertical wells. In this application, the purpose of hydraulic fracturing is to expose additional reservoir surface area for subsequent microbial injection. Once the hydrocarbons are contacted by the microbes, the horizontal fractures are to provide a conductive pathway back to the wellbore for the lower viscosity hydrocarbons to flow.

Two wells in the study area, Fauvergue 1 and 5, were cased, perforated, and hydraulically fracture stimulated. Analysis of the treatments with surface tiltmeters confirmed that horizontal fractures were created. Geomechanical studies conducted prior to fracturing confirmed that the Pennsylvanian sands are more competent and have a greater Young's Modulus than previously reported in the literature.

This paper provides documentation of the extensive laboratory study conducted to develop an understanding of the elastic properties of the Warner and Blue Jacket sandstones and shale, fracture fluid sensitivity, and embedment testing.

The paper also reports the horizontal fracture stimulation execution and pressure analysis. Surface tiltmeter data are reviewed with the hydraulic fracturing performance, to determine whether the treatment objectives were achieved.
Field Trials of a New Method for the Measurement of Formation Gas Using Pulsed-Neutron Instrumentation
Authors: Trcka D. , Gilchrist A. , Riley S. , Bruner M. , Esfandiari T. , Ly T. , Shearin D. , Patino T. , Murray H. , Potter J. , Rose R. , Chen J. , Olsen S. , Lovera O. , McCants D. , Berger A. , Ellsworth K. , Barolak G. , Martain R. , McFall A. , Guo P.
Published: December 2007

This paper presents new hardware and analytical methods for determining formation gas saturation behind casing using pulsed neutron instruments. Instrumentation, characterization, algorithms, and limitations are discussed, and log examples are presented that illustrate the application of the methods in limestone and sand/shale formations.
The Role of Oil Chemistry on the Cold Production of Heavy Oil
Authors: Tang G. -Q. , Temizel C. , Kovscek A. R.
Published: December 2007

Two aspects of cold production of heavy oil are pursued. First, prior experiments have reported that the evolution of the size of mobile gas bubbles exiting a sandpack correlates with recovery by solution gas drive. Generally, systems that exhibit effluent bubbles on the order of the size of pores tend to recover more oil, all other factors equal. To develop an understanding of why gas bubbles remain dispersed in some viscous oils, we have interpreted functional groups present at oil interfaces that may contribute to bubble stability. The readily measured properties include the acid number (mass of base needed to neutralize the oil) and the base number (mass of acid needed to neutralize the oil) as well as the asphaltene content. The acid number quantifies, for instance, carboxylic acid functional groups that are associated with interfacial properties including wettability and interfacial tension. Second, solution gas drive laboratory experiments using three different viscous crude oils are examined in light of acid/base number measurements. The crude oils include two heavy samples from Venezuela and a viscous Alaskan sample. The acid number correlates positively with foamy (i.e, bubbly) oil behavior. The last oil with the least acid number shows no foamy-oil behavior. Effluent gas bubbles are large (2000 to 5000 mm) virtually from the onset of gas flow. Recovery is about 20% of the OOIP. The first two oils display small effluent gas bubbles, low producing gas oil ratio, and slow pressure decline during two-phase, gas-oil flow. The experiments also reaffirm the role of other factors important to heavy-oil solution gas drive including the solution gas-oil ratio, oil viscosity, depletion rate, and initial water saturation.
Successful Hydraulic Fracturing Techniques in Horizontal Wells for Sandstone Formations in the Permian Basin
Authors: Roudakov Vladimir , Rohwer Craig
Published: December 2007

This work summarizes the successful field experience best practices in single-stage hydraulic fracturing of horizontal wells in eastern New Mexico. Horizontal wells are thought to be the solution to increase productivity in formations with low to moderate permeability, great anisotropy, and heterogeneity. While the horizontal wells may produce at an economic rate without stimulation, hydraulic fracturing treatment increases productivity significantly. Multiple-stage fracturing treatments are highly effective, but the cost and risk associated with this type of stimulation often make it unattractive.

This paper presents the summary of more then 20 single-stage treatments in low- to mid-permeability sandstone formations that were successfully completed for several operators. The original wells had cemented liners and employed limited-entry technique to distribute the fracture treatment. An analysis of the treatment techniques in conjunction with the completion methods is presented.

An attempt is made to create the adjustable model of the unified treatment for given conditions to ensure successful hydraulic fracturing of these laterals. Several conclusions are drawn from presented data and design recommendations are made. This paper suggests the critical points in the treatment design and outlines the scope of future research.

The successful techniques, treatments, and practices presented in this paper can be applied globally including application in the fields of western Siberia.
Real-Time Prediction of Shut-in Production From Hurricanes in the Gulf of Mexico
Authors: Watson C. C. , Johnson M. E.
Published: December 2007

Accurate prediction of damage to petroleum production infrastructure from hurricane winds, waves, and storm surges has numerous applications to facility design, production planning, and the financial markets, among others. Here we describe a system for the estimation of damage, repair time, and shut in production using a numerical hurricane model and damage models for various infrastructure components. The system was designed and pilot-tested using data from Hurricane Ivan (2004) and prior storms, and validated operationally in forecast mode during the 2005 hurricane season. The petroleum extraction and distribution systems in the Gulf of Mexico as of 1 May 2005 were stored in a geographic information system. Damage to that infrastructure, consisting of over 50,000 elements, was computed using a three-dimensional physics hurricane model driven by forecast track and intensity data. The resulting damage statistics were then used to derive shut in production predictions for the Katrina and Rita landfalls, the results of which were posted on a web site in real time. The performance of the real time forecast system has been compared to reported statistics and found to accurately predict shut in production, especially using 24 hour forecasts through immediate post storm meteorological data. The validated shut in production prediction model was then applied using the 155 years of existing historical data to produce estimates of the magnitude and frequency with which significant production disruption would have been expected from the Gulf of Mexico facilities, given the present distribution of platforms and on-shore facilities. These frequencies indicate that significant disruptions of production on the order of magnitude seen in 2005 would be relatively common occurrences, given the performance of the infrastructure in recent events and historical hurricane activity. This implies that both design criteria and management of the petroleum production and distribution infrastructure should be revised.
A Four-Component, Two-Phase Flow Model for CO2 Storage and Enhanced Coalbed Methane Recovery
Authors: Seto C. J. , Jessen K. , Orr F. M.
Published: December 2007

Injection of CO2 into deep unminable coal seams is an option for geological storage of CO2. Moreover, injection of CO2 may enhance the recovery CH4 in these systems making coal reservoirs interesting candidates for sequestration.

New analytical solutions are presented for two-phase, three- and four-component flow with volume change on mixing in adsorbing systems. We analyze the simultaneous flow of water and gas containing multiple adsorbing components. The displacement problem is solved by the method of characteristics. Mixtures of N2, CH4, CO2 and H2O are used to represent enhanced coal bed methane recovery processes. The displacement behavior is demonstrated to be strongly dependent on the relative adsorption strength of the gas components.

In ternary systems, two types of solutions result. When a gas rich in CO2 displaces a less strongly adsorbing gas (like CH4), a shock solution results. As the injected gas propagates through the system, CO2 is removed from the mobile phase by adsorption, while desorbed gas propagates ahead of the CO2 front. The adsorption of CO2 reduces the flow velocity of the injected gas, delaying breakthrough and allowing for more CO2 to be sequestered per volume of CH4 produced. For injection gases rich in N2, a decrease in partial pressure is required to displace the preferentially adsorbed CH4, and a rarefaction solution results.

In quaternary displacements with injection gas mixtures of CO2 and N2, the relative adsorption strength of the components result in solutions that exhibit features of both the N2-rich and CO2-rich ternary displacements.

Analytical solutions for enhanced coal bed methane (ECBM) recovery processes provide insight into the complex interplay of adsorption, phase behavior and convection. Improved understanding of the physics of these displacements will aid in developing more efficient and physically accurate techniques for predicting the fate of injected CO2 in the subsurface.
Jetting of Structural Casing in Deepwater Environments: Job Design and Operational Practices
Authors: Akers T. J.
Published: December 2007

Structural casing jetting operations have become commonplace in deepwater environments. Having originated in the Gulf of Mexico, structural casing is now jetted in most deepwater basins in the world. Very little literature has been published regarding jetting practices. Indeed, jetting operations remain as much an art as a science to a large degree. This paper reviews current deepwater structural casing jetting job design and operational practices. Also included are several case histories of jetting failures presented in order to share learnings with the industry and to stimulate the sharing of learnings and practices.
A New Disc One-Cone Bit
Authors: Hu Qin , Liu Qingyou
Published: December 2007

With exploration moving into deeper waters, deserts and plateaus, the geological condition and natural environment faced with by the drilling operation get more complex and worse, so that the difficulty of exploration and development is increasing and the more requirements are put forward to drilling tools. Owing to the extensive application of slim-hole drilling in the world, it is the one of the most important researches for rock bit suppliers and rock bit researchers to develop the efficient small diameter bit.

According to analysis, the rock-breaking efficiency has important relationship with tooth structure and arrangement of teeth. However, owing to the lack of fundamental change on the tooth surface structure of bits in the past tens of years, the drilling speed has nearly not been raised in some special formations. So the new structure of tooth surface must be sought according to the new knowledge for rock-breaking mechanism so as to raise the drilling speed and drilling footage under special environment and some special formations. The disc bit is just the bit with brand-new tooth structure.

After some researches on disc bit and one-cone bit have been done, Southwest Petroleum University (SWPU) has developed a new small size bit with high rotary speed, named disc one-cone bit, which combines the advantages of both one-cone bit and disc bit. This new bit will have expansive application prospect in deep drilling, ultradeep drilling and slim-hole drilling because of its less torsion, higher bottom-hole coverage coefficient and longer bearing life.

In this paper, the experimental study on rock-breaking mechanism of disc one-cone bit is introduced emphatically.
Design and Demonstration of Creating Underground Gas Storage in a Fractured Oil Depleted Carbonate Reservoir
Authors: Xiao Guo , Zhimin Du , Ping Guo , Yuhong Du , Yu Fu , Tao Liang
Published: December 2007

The supply-demand misbalances of natural gas in China require the creation of underground gas storages (UGS) available during peak winter demand and these UGS will probably play an important role in China natural gas market development. As far as know, among existing UGS in China, fractured oil depleted carbonate reservoir converted into UGS is unprecedented. In this paper, a simulation study using both 3D full-field black oil reservoir model and full-field multi-component reservoir model were undertaken to evaluate and demonstrate feasibility of creating UGS in a buried hill fractured oil depleted carbonate reservoir with bottom water, sufficient closure, a good quality and tight cap rock. History matching of the reservoir and single well pressure, water cut, liquid production rate was performed with the full-field black oil reservoir model. The full-field multi-component reservoir model was used to determine total gas storage capacity, working gas capacity, deliverability and injection capacity of the UGS. The simulation study characterized the UGS working mechanism, analyzed its sensitivity, optimized its design parameters, predicted field performance under various operating conditions and recommended the optimized developing UGS plan. Effects of the other three buried hills on the UGS are also incorporated into the two reservoir models. CNPC is further verifying our research efforts to decide duration of the UGS project.
Improved Density Processing for LWD Density
Authors: Desport O. , Crowe J.
Published: December 2007

Density measurements are intrinsically sensitive to standoff. In wireline logging, it is possible to have the detectors on a pad, reduce the standoff to a minimum, and correct for other effects with a high-level of accuracy. Logging while drilling (LWD) is more challenging because the standoff is much more important than with wireline tools, even in the case of a stabilized tool. The traditional spine-andrib technique loses accuracy with high standoff and can be clearly seen with LWD measurements. The common effects are separation between the quadrant densities, density images dominated by eccentricity, and undercorrected density in sliding zones. Image-derived processing, implemented by selecting the sectors where the tool is the closest to the borehole, greatly improves the LWD density measurements but does not solve the case where standoff is too high in every sector or when the tool is sliding. It also does not correct the density image. The processing method presented in this paper offers a different approach to this problem, and the information from the sector measurements is used to build up a more stable density correction than the traditional spine-andrib algorithm. This new technique can be applied to the quadrant densities as well as the sector densities.

This processing method can be applied to old or new wells. With the improved robustness to standoff, most of the sliding zone can be corrected by making LWD density in formation evaluation much more accurate. Using the quadrant density corrections, an estimation of uncertainty of the correction can be computed, which can be very useful in the sliding zone, where only one density value is available.

This processing method was applied in two field studies in Nigeria and good density data were recovered in every well in all the zones with high standoff, including the sliding zones. The few wells in this field where both wireline and LWD logs were acquired confirmed the quality and accuracy of the corrected LWD density measurements.
Differential Cased Hole Sonic Anisotropy for Evaluation of Propped Fracture Geometry in Western Siberia, Russia
Authors: Nikitin A. , Pasynkov A. , Makarytchev G. , Maniere J. , Kalyanaraman R. Sunder , Tcherkashnev S.
Published: December 2007

In a waterflooded reservoir, hydrocarbon recovery optimization is impacted by well spacing and hydraulic fracture extent. An excessive fracture length may lead to an earlier than desired increase in water cut. Uncertainty in propped fracture dimension is related to the distribution of stresses and elastic properties, as well as fluid leak off. Those factors have strong implication on proppant distribution, especially when larger size proppant are used. Although the latter could lead to more conductive fractures, they could also bridge at the wellbore, impeding both lateral and vertical extent.

Differential cased hole sonic anisotropy (DCHSA) combines the use of cross-dipole shear sonic analysis carried out before and after hydraulic fracturing and adequately supported by other logs (ultra-sonic cement evaluation) to infer the change in anisotropy; the latter anisotropy includes the creation of a propped width. While the methodology has been used in carbonates, very few cases of its application in turbidites have been documented.

Differential cased hole sonic anisotropy (DCHSA) can be determined from analysing cross-dipole shear sonic data acquired before and after hydraulic fracturing. From analysis of other log data, such as the ultra-sonic cement evaluation tool, it is possible to infer change in anisotropy, which can indicate the creation of a propped fracture.

In this paper, the results from a DCHSA and hydraulic fracture campaign in a Western Siberian oil field are presented. In this field, the common well development practice consists of multiple, large job fracturing treatments, ranging from 100 to 300 tons, using large sized proppant. It is generally believed that a high stress barrier, above and below reservoir interval, will facilitate the bridging of proppants, and will cause an artificial barrier. Planar 3D models that incorporate stress detail, moduli width calculation, 2D flow proppant tracking and bridging criteria are available to the industry, but do need extensive set of accurate parameters. These models will be greatly enhanced by calibration from direct measurements of the fracture geometry. DCHSA has proved instrumental in detecting fracture induced anisotropy. Fracture heights were modeled with the expected treatment pressures. The outcome proved a valuable methodology that decreased the operational and production risks that are associated with hydraulic fracturing using large proppant sizes.
Improved Acid Diversion Design Using a Placement Simulator
Authors: Glasbergen Gerard , Buijse Marten
Published: December 2007

In matrix-acidizing long intervals, diversion is essential to obtain good placement of the reactive fluids. Over the years, several diversion techniques have been applied, resulting in improved zonal coverage. These diversion methods can be divided in mechanical methods such as the use of balls to seal the perforations and chemical methods such as gelled fluids.

In the design of matrix acid treatments, placement models that predict the zonal coverage of the fluids are of great help. These models improve the understanding of the complex processes and will help to improve the design of matrix-acid treatments. For studying diversion effects, correct modeling of the diversion methods in a placement simulator is essential. We have developed such a fluid placement simulator (FPS) that contains models for the different diversion methods.

In this paper, we will give an overview of the different diversion methods and their application. Further, we will discuss the implementation of the models in a comprehensive FPS. We will show how this simulator can be used to optimize placement and diversion. Validation of the models will be presented based on the analysis of two case histories.

In an acid treatment, the fluid diversion design is often based on guidelines, rules-of-thumb, and an intuitive idea on how diversion "works." Simulators are not used, usually because they are not available. However, the use of a diversion simulator will show that many of the guidelines and intuitive ideas are wrong, or at least incomplete; this will be illustrated with example calculations.
History Matching Using the Ensemble Kalman Filter on a North Sea Field Case
Authors: Haugen V. , Natvik L. -J. , Evensen G. , Berg A. , Flornes K. , Nævdal G.
Published: December 2007

Recently, the ensemble Kalman filter (EnKF) has been examined in several synthetic cases as an alternative to traditional history matching methods. Results from these studies indicate that the method can be useful for estimation of permeability and porosity fields.

Contrary to other history matching methods, the EnKF provides an ensemble of model realizations containing information of the uncertainty in the estimates. Moreover, the data is processed sequentially, which makes it possible to always have an updated model conditioned on the most recent production data. The method therefore seems promising for real time reservoir management. This paper presents a successful study for a North Sea field case, where real production data have been assimilated using EnKF.
Technologies for Arctic Offshore Exploration & Development
Authors: Matskevitch Dmitri G.
Published: December 2007

Exploration and development of hydrocarbon reserves in the Arctic seas are challenged by a harsh environment including presence of ice and icebergs, permafrost, low temperatures, and extended periods of darkness. Remoteness and ecological considerations make activities in the Arctic even more difficult. Advanced technologies, non-traditional technical solutions and flawless execution are required to make any major project in the Arctic a success.

Understanding the difficulties associated with implementing an offshore project in the Arctic comes with experience. In ExxonMobil's case, this results from 40 years of Arctic field operations and associated research. This paper discusses the Arctic technologies developed to support ExxonMobil exploration and development activities in the Arctic seas.

ExxonMobil's Arctic offshore activity started in 1966 with the installation of the ice-resistant Granite Point offshore platform, which is still producing oil in Cook Inlet, Alaska. Since then ExxonMobil has constructed and drilled from artificial islands in shallow arctic waters, drilled in iceberg prone regions off Greenland, Canada and Norway, designed and installed the first iceberg-resistant gravity-based platform on the Grand Banks, installed an ice-resistant production platform and the first in-ice SPM offshore loading facility offshore Sakhalin Island, and continued to develop methodology to provide rational design criteria for ice-resistant production platforms. Development of design criteria and the selection of the most reliable and cost-effective technical solutions for arctic offshore projects required data from numerous field expeditions, model tests programs, field measurements, and observations from existing offshore structures. These studies were carried out under the supervision of ExxonMobil research staff.

Arctic marine transportation systems are also an important element for many offshore and near-shore projects in remote areas where the construction of export pipelines is prohibitively expensive. The "Manhattan" tanker trials in 1969–70 in the US and Canadian Arctic and the 2002 "Primorye" trials in the Tatar Strait have helped ExxonMobil develop safe and reliable technologies for hydrocarbon transportation in ice-infested waters.
Accurate Detection and Spatial Delineation of Thin-Sand Sedimentary Sequences via Joint Stochastic Inversion of Well Logs and 3D Prestack Seismic Amplitude Data
Authors: Merletti G. D. , Torres-Verdín C.
Published: December 2007

We describe the successful application of a new pre-stack stochastic inversion algorithm to the spatial delineation of thin reservoir units otherwise poorly defined with deterministic inversion procedures. The inversion algorithm effectively combines the high vertical resolution of wireline logs with the relatively dense horizontal coverage of 3D pre-stack seismic amplitude data. Multiple partial-angle stacks of seismic amplitude data provide the degrees of freedom necessary to estimate spatial distributions of lithotype and P- and S-wave velocities in a high-resolution stratigraphic/sedimentary grid. In turn, the estimated volumes of P- and S-wave velocity permit the statistical co-simulation of lithotype-dependent spatial distributions of porosity and permeability.

The new stochastic inversion algorithm uses a Bayesian maximization criterion to populate values of lithotype and P- and S-wave velocities in the 3D simulation grid between wells. Property values are accepted by the Bayesian selection criterion only when they increase the statistical correlation between the simulated and recorded seismic amplitudes of all partial-angle stacks. Furthermore, inversion results are conditioned by the predefined measures of spatial correlation (variograms) of the unknown properties, their statistical cross-correlation, and the assumed global lithotype proportions.

Using field data acquired in a fluvial-deltaic sedimentary rock sequence, we show that deterministic pre-stack seismic inversion techniques fail to delineate thin reservoir units (10-15m) penetrated by wells because of insufficient vertical resolution and low contrast of elastic properties. By comparison, the new stochastic inversion yields spatial distributions of lithotype and elastic properties with a vertical resolution between 10-15m that accurately describe spatial trends of clinoform sedimentary sequences and their associated reservoir units.

Blind-well tests and cross-validation of inversion results confirm the reliability of the estimated distributions of lithotype and P- and S-wave velocities. Inversion results provide new insight to the spatial and petrophysical character of existing flow units and enable the efficient planning of primary and secondary hydrocarbon recovery operations.
Shape Factor in Fractured Reservoir Simulation
Authors: van Heel A. P. G. , Boerrigter P. M.
Published: December 2007

The shape-factor concept, originally introduced by Barenblatt in 1960, provides an elegant and powerful upscaling method for fractured reservoir simulation.

Since its introduction, many different values for the shape-factor have been proposed in the literature, among which the well-known Warren and Root, and Kazemi shape-factors. Different shape-factors can lead to totally different reservoir behaviour, so the selection of the appropriate shape-factor value is critical for accurate modelling.

The aim of this paper is to show that the selection of the appropriate shape-factor should not only depend on the "shape" and dimensions of matrix blocks, but should also take into consideration the character of the dominant underlying physical recovery mechanisms, convection or diffusion. We wil show that by taking into account the dominant physical recovery mechanism, the apparent discrepancies in the shape-factor values reported in the literature can be overcome.

We present concrete recommendations as to which shape-factor values to use in fractured reservoir simulations. We briefly review the shape-factors presented in the literature and argue that convection and diffusion-governed processes should be modelled using different shape-factors. We compare and contrast the predictions of different shape-factors for the case of steam-enhanced gravity drainage of viscous oil in a fractured reservoir.