bluuebunny/crossref_metadata_2025 huggingface dataset:
New Development Case History: Midnight Sun
Authors: Eck Daniel J. , Reinbold Eric W. , Lundgren Carl E. , Daggett Paul H. , Westergaard Edwin H. , Rollins Francis O. , Young Jim P. , Bakun Frederick E.
Published: December 2007

The Midnight Sun field is located on the North Slope of Alaska near Prudhoe Bay (Figure 1). The field was discovered in 1997 by ARCO Alaska, Inc. and Exxon when drilling the Sambuca #1 exploration well. The discovery well encountered approximately 100’ of high quality Kuparuk sand analogous to the adjacent Pt. McIntyre field. The field was further delineated in 1998 with the Midnight Sun #1 well. Proximity to Prudhoe Bay infrastructure allowed early production from the Midnight Sun reservoir with production commencing in October 1998.

The Midnight Sun accumulation occurs in a low relief graben, containing an estimated 40 to 60 MMSTB of Original Oil In Place (OOIP). A gas oil contact (GOC) extends over a significant portion of the reservoir.

A 3D reservoir simulation model was constructed, calibrated to early field performance and used to study development options. A mid-field waterflood was identified as the best development plan. Simulation runs indicated that the mid-field waterflood would provide good recovery while isolating the upstructure gas cap for future depletion.

Waterflood operations commenced in October of 2000 using produced water from the Prudhoe Bay facility. Waterflood response was observed in the third quarter of 2001, characterized by increased oil production rate and a dramatic GOR collapse. Three additional wells were drilled in the fourth quarter of 2001 to complete the Phase II drilling program. Results from these wells have confirmed the geologic model used for development planning.
Performing a High Resolution surface Gravity Survey to Monitor the Gas Cap Water Injection Project, Prudhoe Bay, Alaska
Authors: Brady Jerry L. , Ferguson John F. , Aiken Carlos V. L. , Seibert John E. , Chen Tianyou , Hare Jennifer L.
Published: December 2007

The world’s first 4-D surface gravity surveillance of a waterflood is being implemented at Prudhoe Bay, Alaska. This monitoring technique is an essential component of the surveillance program for the Gas Cap Waterflood Project. A major factor in the approval process for the waterflood was to show that water movement could be economically monitored, with a very limited number of wells penetrating the waterflood area. Conventional monitoring techniques would have been cost prohibitive since they would have required the drilling of numerous surveillance wells. Modeling studies indicate that density changes associated with water replacing gas can be readily detected using high-resolution surface gravity measurements. Modeling of the gravity data determines the mass distribution, mass balance and flood front location.

This paper will focus on how to perform an extremely accurate, high-resolution surface gravity survey in the Arctic. Details on survey methodology, meter testing and calibration will be covered. The use of gravity meters in combination with the NAVSTAR Global Positioning System (GPS) for location and elevation will be described. Field tests at Prudhoe Bay indicate that gravity survey accuracy of 5-10 µGal can be achieved using relative gravity meters in combination with GPS. Model results, using reservoir simulations, have indicated that gravity surveys with this accuracy should be able to account for greater than 95% of the injected water.
Permanent Fiber Optic Monitoring at Northstar: System Installation
Authors: Pruett Eddie , Abshire Phil , Holt Barbara M , Sherritt J. Allen
Published: December 2007

BP's Northstar field, on the North Slope of Alaska, represents the first multi-well, new field development to incorporate downhole fiber optic pressure and temperature monitoring. Between 2001 and 2003, permanent fiber optic pressure and temperature gauges will be installed in 16 wells. This paper discusses the installation of the first 6 fiber optic systems at Northstar in the winter of 2001. All aspects of the installations will be described, including planning, logistics, run-in-hole during completion, and system commissioning. Elements common to and different from conventional gauge installations will be examined. In particular, special requirements for a fiber optic system installation in an arctic environment will be identified.
Production Logging Advances in the Fractured Monterey
Authors: Grayson S. T. , Kohring J. J. , Elliot W. B. , Hertfelder G. P. , Goeres T. B. , Horner S. G.
Published: December 2007

Accurate production profiling in the fractured Monterey wells of offshore California is a challenging endeavor. Deviated wells, three-phase flow, and the unpredictable nature of production from natural fractures, makes possible almost any type of flow regime. New production logging sensors have been developed that use distributed probes to directly detect hydrocarbons and provide images of the flow profile. The FloView*, PSP, and GHOST* tools have been used in the Monterey to provide accurate profile data necessary for successful workover efforts. When these data are combined with fluid PVT data in flow modeling software, oil, gas, and water contributions from each perf interval are quantified. Based on this analysis, thru-tubing water shutoff workovers have been designed and successfully implemented in a number of Monterey wells. First hydrocarbon entry is clearly visible on the FloView field image, and the modeling software quantifies the reduction of water with the precise placement of a thru-tubing bridge plug. The caliper measurements included with the PSP provide enhanced spinner interpretation when casing ID changes unexpectedly. The distributed probes of the Ghost tool use optical refractance to positively identify gas in the borehole. With a clear picture of the situation, pinpoint accuracy can be applied when implementing the solution. In the Monterey, the results can be dramatic.
Establishing Gas Phase Well Performance for Gas Condensate Wells Producing Under Three-Phase Conditions
Authors: Jokhio Sarfraz A. , Tiab Djebbar
Published: December 2007

This paper provides a new method of forecasting natural gas production of gas-condensate wells that flow under three phase conditions. Such wells include gas condensate wells that produce liquid condensate and water along with gas phase, their main production. Mathematically treating such systems can be very demanding. A new tedious, but simple method of projecting the gas phase production is proposed. In this method we integrate reservoir production data and the pressure transient data to forecast well performance without prior knowledge of relative permeability as function of saturation. Since pressure transient well test data is usually available on yearly basis, effective permeability as a function of pressure can be updated. It is the true representative of the reservoir conditions of heterogeneity, geometry, and resident fluids.

The total gas production in a gas condensate reservoir is contribution of all the three regions that might exist at certain stage of depletion. Free and dissolved gas in both oil and water in Region-1, free and dissolved gas in water in Region-2, and free and dissolved gas in water in Region-3. Thus to project the production, along with the physical properties of fluids in all the three regions, their phase change with pressure also has to be handled.

It is observed from the solved examples that buildup of condensate liquid phase reduces the gas production as well as water production, a favorable situations. Partially the gas production loss is recovered in form of condensate while reducing water production.

Finally, few examples with simulated data are analyzed to show the use of new method. A step-by-step procedure is also devised to establish the well performance. Small operators will benefit from this method at the most, since data acquisition like relative permeability curves requires to laboratory experiments on cores.

Introduction

We are extending our understanding of the retrograde gas-condensate systems lately. Recently many good papers have been published that treat gas-condensate systems. Retrograde gas-condensate reservoirs are primarily gas reservoirs. A zone of liquid begins to form as the dew point pressure is reached. The liquid keeps accumulating and does not flow until the critical liquid saturation is reached. Once critical saturation of the liquid phase is reached, it begins to flow towards the wellbore along with the gas. Pressure at this point in the reservoir is termed as P*. Interestingly, this liquid may re-vaporize as the pressure further crosses the lower line on two-phase envelope of phase diagram. This behavior of re-vaporization of the oil phase is called the "Retrograde behavior." Fig.1, Fig.2, Fig.3, and Fig.4 show the schematics of such a phenomenon in vertical wells and horizontal wells.
Evidence and Implications for Significant Late and Post-Fold Fracturing on Detachment Folds in the Lisburne Group of the Northeastern Books Range
Authors: Bui T. D. , Brinton J. , Karpov A. V. , Hanks C. L. , Jensen J. L.
Published: December 2007

In exposed detachment-folded Lisburne Group carbonates, field evidence and statistical analysis suggest that a significant population of fractures post-date folding.

Both prefold fractures and penetrative strain associated with peak folding are overprinted by late-folding and post-folding fractures. The fractures in the first set strike EW parallel to the fold axis, are perpendicular to bedding, are often only partially filled with cement, and generally terminate at bedding planes. These and the earlier structures are consistently overprinted by pervasive late NS extension fractures. The later fractures strike perpendicular to the fold axes, are vertically extensive, evenly spaced and unfilled. Both have similar average and median spacings.

Statistical analysis of fold angle and fracture spacing indicates that, as the folds tighten, both the EW and NS fracture spacing increases by a factor of two or three and becomes slightly more variable. This behavior is opposite from that expected if the fractures were closely related to folding. It suggests that the two sets are similar to each other and are only weakly affected by the folding.

This weak genetic relationship between folding and formation of the most obvious and open fractures serves as an important example with major consequences for reservoir modelling. Complex genetic and timing relationships between fractures and folds may result in several fracture sets, each having different characteristics (e.g., size, amount of fill, and termination type). Unless recognized, genetically disparate fractures may be combined into one or a few sets to produce a reservoir model with fracture properties which do not apply to any of the sets. This could result in inappropriate wellbore placement or inaccurate productivity and recovery estimates.
Characterization of Flow Channels, Natural Fractures Orientation and Oil Water Contact Movement from Well Productivity Data
Authors: Zahedi Alireza , Ershaghi Iraj , Horner Steve
Published: December 2007

This paper presents application of innovative conventional reservoir engineering methods to map fracture systems and to track fluid interface movement in naturally fractured reservoirs. Particular emphasis is on reservoirs with fractured-controlled production such as the prolific Monterey Formations in the Pacific Offshore. These reservoirs are characterized by very complex fracture network and trivial matrix porosity. Monterey Formations exhibit unique fracture structures where fault zones and other highly brecciated intervals serve as large conduits of interface and fluid movement. The inspiration for the study is from observations on the South Ellwood Field located off the Coast of Santa Barbara, California.

In the absence of modern fracture identification logs, we developed a methodology to map fractures from individual well productivity and course direction. We introduce a fracture orientation estimation method based on the projected length of the well path, completion profile and cumulative oil. The optimization method correlates well productivities with incident angle of the directional well course, anticipated direction of tectonically generated fractures and the length of wellbore exposure to fractured intervals.

To account for the observed uneven oil-water contact (OWC) in individual brecciated intervals, a saturation tracking methodology is proposed extending the aquifer modeling approach originally proposed by Fetkovich and the transient monitoring of OWC using the Ershaghi x-plot method.

These innovative conventional reservoir engineering analysis techniques deciphering signals imbedded in performance history constitute effective pre-processing steps to building a realistic fracture model for the 3-D simulation of the reservoir.
Experimental Verification of Methods to Calculate Relative Permeability Using Capillary Pressure Data
Authors: Li Kewen , Horne Roland N.
Published: December 2007

The Brooks and Corey model has been accepted widely to calculate relative permeability using capillary pressure data. However the Purcell model was found to be the best fit to the experimental data of the wetting phase relative permeability for the cases studied, as long as the measured capillary pressure curve had the same residual saturation as the relative permeability curve. The differences between the experimental and the Purcell model data were almost negligible. A physical model was developed to explain the insignificance of the effect of tortuosity on the wetting-phase. For nonwetting phase relative permeability, the model results were very close to the experimental values in drainage except for the Purcell model. However, calculated data in imbibition were different than the experimental data. This study showed that relative permeability could be calculated satisfactorily by choosing a suitable capillary pressure technique, especially in drainage processes. In the reverse procedure, capillary pressure could also be computed once relative permeability data are available.
Implementation of an Ultrasonic Cuttings Processing System for Drilling Operations at the Meltwater Field, North Slope, Alaska
Authors: Brockway Thomas A. , Andrews Lloyd , Caza Stan , Simpson Dave
Published: December 2007

This paper describes the successful implementation of a new generation cuttings disposal system being used by Phillips Alaska, Inc. to replace conventional ball mill slurrification at the Meltwater satellite development project.

The vibrating ball mill is currently the dominant technology used on the Alaskan North Slope for processing cuttings and fluids generated during the drilling process. While effective, ball mills have three inherently inefficient and undesirable characteristics – they are large, noisy, and expensive to operate and maintain.

In early 2001, Phillips Alaska, Inc. and Doyon Drilling began researching alternative cuttings disposal solutions for development drilling at Meltwater, a remotely located satellite development project south of the main Kuparuk River Field. A new technology alternative to the traditional ball mill was employed combining ultrasonic cuttings processors, a separation shaker, process pit, and an injection skid into a small, lightweight, and highly mobile unit. To date, this new cuttings processing system has proven to be reliable and highly effective, providing slurry outputs comparable to a traditional ball mill, but with substantial size and cost reductions.

This paper will give a brief overview of the history of the ultrasonic processing system, describe some of the theory behind ultrasonic processing, and illustrate how ultrasonic units are being utilized as part of an overall cuttings disposal "system" on the Meltwater project. An operational and cost comparison between the Meltwater ultrasonic system and a conventional ball mill will also be presented.
Testing and Startup of a Novel Compressor for Miscible Gas Injection
Authors: Klein John M.
Published: December 2007

This paper describes experience with an interesting new high-pressure application of an all-electric centrifugal compressor for miscible injection. Improvements made during the shop testing of the machine were responsible for reducing mechanical issues in the field. However, commissioning and startup proved challenging. Process control of the MI mixture to the compressor was one of several issues that required field resolution in order to complete the start-up.
Maintenance Decision Support Tools for CMMS
Authors: Mofley Guy A. , Cowart J. R.
Published: December 2007

We are all familiar with thinking in terms of upstream and downstream; even oil and gas. However, there is a new product stream that has not captured our attention and is rarely considered: the data stream. Once converted to information, this stream enables processed data, demands an audience, and encourages solutions while requiring technology to better visualize themes. Truly valuing information, leads to better decision making support tools and thus increases the profitability quotient.
Use of Magnetic Clutch to Improve Performance of Sucker Rod Pumps
Authors: Guo Boyun , Zhang Morgan , Jin Feng
Published: December 2007

This paper reports a new type of overrunning clutch that has been developed and installed on sucker rod pumping units. The clutch disengages the power-input shaft of the gear reducer and the unit sheave, and allows free-fall motion of the sucker rod string in down-stroke. Based on the results of more than 100 installations, it was found that the pumping speed increased by 9% in average. Liquid production rate increased by up to 30%. Power saving was 23.6% on average. It was also observed that downhole sand and paraffin deposit problems were greatly alleviated. This paper presents pump performance analyses and clutch selection for sucker rod pumping systems.
Perspective on the Evolution of Petroleum Engineering Education in the New Millennium
Authors: Agbaraji Casmir I. , Khataniar Santanu , Chukwu Godwin A. , Zhu Tao
Published: December 2007

Engineering education, in general, has been undergoing significant changes in recent years with the arrival of groundbreaking technology. Because of this technological revolution, globalization of the economy, and changing perspective on energy issues, the education of petroleum engineers needs to evolve to meet the challenges of the future petroleum industry. The petroleum industry has become more service oriented and diversified than ever before. This will lead to the role of an engineer as a creator of public goods, which are not necessarily tangible, as warranted by the industry. The objectives of this study are to identify the critical challenges facing petroleum engineering education today, to analyze the vision of petroleum engineering in future, and to develop a plan to meet the future educational challenges. The tools available for petroleum engineering education in the past and in the present are reviewed, and those expected to dominate the 21st century are analyzed. The impact of new technological devices on the delivery, quality, scope, and recipient of petroleum education is critically evaluated. The evolving shift in learning model from a traditional, school based one to a non-conventional, virtual one is discussed. The areas of petroleum engineering education that need improvement are highlighted. It is clear that engineering education will be challenged as never before to shape the nature and quality of life in the new millennium. Engineering education must be proactive to meet these challenges.
Near-Well Radial Upscaling for the Accurate Modeling of Nonconventional Wells
Authors: Wolfsteiner Christian , Durlofsky Louis J.
Published: December 2007

The accurate modeling of wells that exhibit arbitrary trajectories and/or multiple laterals (i.e., nonconventional wells) is critical for obtaining reliable well performance predictions. Modeling strategies need to account for both well geometry and reservoir heterogeneity effects, especially in the near-well region. Multiblock grids offer the ability to model complex wells more accurately than standard finite difference procedures. Such grids are globally unstructured, yet maintain structure locally, making them a reasonable compromise between standard (fully structured) techniques and fully unstructured procedures.

In this paper, we develop a near-well upscaling procedure suitable for use with multiblock grids. The technique is applicable for grids that are radial (or nearly so) in the near-well region rather than rectangular. The method is well-suited for models in which the general well trajectory is resolved by the simulation grid and is capable of modeling reservoir heterogeneity down to the scale of the wellbore itself. The high degree of accuracy of the upscaling technique is demonstrated through comparison to fine grid calculations for two different types of reservoir heterogeneity. It is shown that the effects of near-well heterogeneity can be significant and that the new procedure provides much better accuracy than simpler well models that assume near-well homogeneity and isotropy.
Carrying Capacity Design for Directional Wells
Authors: Jawad Riayde H. , Akgun Ferda
Published: December 2007

Effective hole cleaning is an important task in directional and/or horizontal well drilling. Inadequate hole cleaning can lead to severe problems such as; stuck pipe, high rotary torque, low penetration rate and cutting bed formation which may lead to micro channel formation.

It is well known that for the same drilling conditions the directional wells require significantly higher flow rates than that of vertical ones in order to obtain the same cleaning efficiency. However, for many cases the required flow rates are not practically achievable due to pump limitations and/or borehole washouts.

Determining cutting carrying capacity by assuming concentric annulus is far from realistic for horizontal and deviated wells as the pipes have a tendency to lay on the low side of the hole under the influence of gravity. Therefore, it becomes necessary to develop a design model for drilling fluid carrying capacity for directional wells taking into consideration the actual mechanism of cutting transport through an inclined eccentric annulus.

A new design model for cutting carrying capacity for directional wells has been developed in this study by taking into consideration the non-Newtonian flow through an inclined eccentric annulus for both laminar and turbulent flow regimes. The proposed method calls for the determination of four different flow rates. The first one is the minimum flow rate required to ensure the flow occurs through the entire eccentric annulus (i.e., there is no stagnant fluid). The second one is the critical flow rate below which the pipe may get stuck due to cutting bed formation. The third one is the minimum rate above which the particles are not able to segregate and form steady bed. The fourth one is the optimum flow rate, which minimizes the bottom hole hydrodynamic pressure. Then these flow rates are compared with each other in order to obtain the recommended flow rate for a given drilling condition.
Cement Matrix Evaluation
Authors: Al Hammad Mansour A. , Altameimi Yehya M.
Published: December 2007

In the Saudi Aramco gas campaign, during the last few years, a high casing-casing annulus phenomenon was observed clearly days or months after rig released. Some of these casing or liner set and cemented across abnormally pressured formations, which contains salt water, gas or combinations of both. These zones were cemented using various cement density ranging from normal to high-density slurries.

The integrity of cement sheath is commonly measured by its ability to provide long term zonal isolation, at the time of completion and for the life of the well. It also has to physically support the casing, withstand pressure cycles, temperature cycles and protect the casing against corrosive fluids. Not all cement applications perform these functions with equal success, and many of those that do, they do not stand up against the forces that exert upon them during time.

This paper is evaluating the expansion and the shrinkage property using class " G" cement in Saudi Arabia, and its effect on the cement matrix. One of the potential problems causing the failure of cement zonal isolation, can be attribute to the over use of chemical expansion additives. The cement bond failure can cause migration of fluid from one zone to another, losses of reservoir fluid, well control issues and poor stimulation operations.
Multiple Zone Open Hole Gravel Packing Techniques with Zonal Isolation
Authors: Corbett T. Gary , Vickery E. Harold
Published: December 2007

This paper describes techniques to gravel pack multiple pay zones in a single open hole wellbore with positive zonal isolation between zones. For vertical and moderately deviated wells, these techniques provide an alternative to traditional stacked cased hole frac-packs. Open hole gravel packing eliminates the cost of cementing and perforating casing and can be pumped with considerably less hydraulic horsepower and blending equipment than a cased hole frac-pack. Therefore, open hole gravel packs can be performed at lower cost using more readily available, skid mounted equipment set on the rig versus a stimulation vessel typically required for frac-packs.

In addition, using current state-of-the-art technology, open hole gravel packs are capable of achieving high efficiency well completions with little or no productivity impairment. Open hole gravel packing has typically been limited to single massive sandstone reservoirs or the bottom pay zone in wells containing multiple zones. The techniques described in this paper allow open hole gravel packs to be applied in wellbores intersecting multiple pay zones. These methods can save considerable time and cost in suitable candidate wells.
Advanced Evaluation of Transitional Zones for Drilling Optimization
Authors: Khafizov Segey F. , Syngaevsky Pavel E.
Published: December 2007

The paper reviews tectonic influence on pore pressure distribution in overpressured sealing zones, and their recognition on logs. Based on materials from West Siberia (Russia) and Gulf-of-Mexico (Texas and Louisiana) a study of tectonic and diagenetic impact on transitional zones forming and associated drilling problems is performed.

Faults play an important role in overpressure forming, but they can also cause partial or total damage of the seal. A fault can enhance sealing properties of shale cap or partially destroy them, allow «escape» of formation fluids and pressures from down-dip formations, forming a shallow overpressure zone (Matagorda Island 622/623 and East Cameroon). Various stages of shale diagenesis are related to water expulsion and can aid to abnormally height formation pressure forming. A nature of Bazenov abnormal pressure is related to TOC (total organic carbon) alteration, specifically to hydrocarbon generation. This overpressure was "translated" into Abalak shaly formation with complex fractured-cavernous reservoirs (Severo-Demyanskoe, Em-Egovskoe fields). Both events are causing drilling problems and could be recognized on NMR (nuclear-magnetic resonance) and conventional (resistivity, gamma-ray) log diagrams. By incorporating such information into the drilling model one can characterize complex formations and avoid them when possible from penetrating.
Application of Leaky Aquifer Type Curves for Coalbed Methane Characterization
Authors: Cox D. O. , Onsager P. R.
Published: December 2007

Many coalbed methane (CBM) reservoirs are part of larger aquifer units that also contain water-saturated sandstones. To account for connections to aquifers, this paper presents "leaky aquifer" type curves for radial flow in leaky aquifers with wellbore storage and skin, and for vertically fractured wells in leaky aquifers. The type curves are similar to those with a constant pressure boundary, and in some cases, the characteristic flat derivative of infinite-acting radial flow may be completely masked. Examples from several CBM basins are presented that demonstrate the methodology.
Role of Fracture Flow in Matrix-Fracture Transfer
Authors: Gautam P. S. , Mohanty K. K.
Published: December 2007

Although a lot of research has been done in modeling the oil recovery from fractured reservoirs by countercurrent imbibition, less attention has been paid in the past to the effect of the fracture fluid velocity upon the rate of oil recovery. Assuming oil saturation continuity at the matrix-fracture interface, we propose a droplet detachment model to arrive at an effective water saturation in a thin boundary layer at the matrix-fracture interface. This effective boundary water saturation is a function of fluid type, fluid velocity in the fracture and fracture geometry. For a highly water-wet reservoir, this model predicts that the increase in fracture fluid velocity would result in a higher boundary water saturation a matrix is exposed to, which in turn would increase the oil recovery rate from the matrix. It also predicts that the oil recovery rate does not scale linearly with the boundary water saturation. It also implies existence of an optimum fluid velocity through the fracture of a known geometry that maximizes oil/water ratio. The model predictions are compared with preliminary experimental results.
Pressure-Pressure Convolution Analysis of Multiprobe and Packer-Probe Wireline Formation Tester Data
Authors: Onur M. , Hegeman P. S. , Kuchuk F. J.
Published: December 2007

In cases where flow rate data are not reliable, the need for flow rate in estimating permeability from wireline formation tester multiprobe and packer-probe pressure data sets can be eliminated by the use of the so-called pressure-pressure (p-p) convolution. The p-p convolution is based on the use of two different pressure data sets recorded at different spatial locations and, thus, enables one to perform parameter estimation without flow rate. In this work, we present a detailed analysis of multiprobe and packer-probe pressure transient tests by considering various p-p convolution options. Both single layer and multilayer (crossflow) systems are considered. Approximate equations that apply during spherical and radial flow for a vertical well in a single layer system for various p-p convolution options are derived. These equations indicate which parameters can be uniquely determined from p-p convolution. It is shown that p-p convolution analysis can sometimes provide nonunique parameter estimates. Also, we provide a flow rate extraction method that proves useful to check the validity of parameter estimates obtained from p-p convolution analysis. Two example tests, a synthetic multiprobe test and a field packer-probe test, are provided to illustrate the methodology and procedures developed in this work.
Light Annular MudCap Drilling - A Well Control Technique for Naturally Fractured Formations
Authors: Colbert John W. , Medley George
Published: December 2007

Light Annular MudCap drilling (LAMCD) is a safecost effective drilling technique that may be used to drill through massively fractured formations or where Karsts are prevalent, especially when productive fluids are sour. It is an adaptation to regular Mud Cap Drilling (MCD), used to drill formations such as the Austin Chalk. The technique was first developed and used in the Cogollo formation in South America and has recently been used to drill sour formations in Kazakhstan. The LAMCD technique allows the driller to control and monitor the amount of sour gas migrating into the annulus.

Drilling through formations containing multiple large fractures using conventional well control techniques is impossible unless the fractures are sealed. In many cases where extremely large fractures or karsts (vugs/caverns) have been encountered, lost circulation technology has proven to be unsuccessful.1-7 If the fractured formation being drilled is a pay interval, plugging the fractures is counter-productive.

The LAMCD well control/lost circulation technique entails drilling with the choke completely closed while using a rotating control device (RCD) to seal the annulus. A sacrificial fluid, usually fresh or brine water is injected down the drill pipe. The drilled cuttings are transported and deposited into the fractures or vugs. The annulus is periodically injected with a viscous fluid that has a density slightly less than the pore pressure equivalent, hence the name "Light Annular MudCap". This controlled displacement process results in a predictive positive casing pressure. The casing pressure will increase as hydrocarbons migrate up the annulus. The value of the casing pressure qualitatively corresponds to the height of the hydrocarbon migration. Once a predetermined casing pressure/height is reached, LAMC fluid is pumped into the annulus until all the hydrocarbon is displaced back into the formation. After all the hydrocarbons are purged from the wellbore, the casing pressure will return to a constant and predictable value.

LAMCD is a well control/lost circulation technique that allows drilling through massive lost circulation zones without downtime associated with lost circulation and conventional well control. Penetration rates are increased significantly as well.

This paper describes the application of Light Annular MudCap Drilling as well as the details of the method. Well control and equipment issues are addressed. Simple equations for estimating pressure and volume requirements during LAMCD are presented.
A New Skin Factor Model for Perforated Horizontal Wells
Authors: Furui K. , Zhu D. , Hill A. D.
Published: December 2007

Using a combination of analytical calculations and 3D finite element simulation, we have developed a comprehensive skin factor model for perforated horizontal wells. In this paper, we present the mathematical model development, and validation of the model by comparison with finite element simulation results. With the new perforation skin model, we then show how to optimize horizontal well perforating to maximize well productivity.

A cased, perforated well may have lower productivity (as characterized by a positive skin factor) relative to the equivalent openhole completion because of two factors – the convergence of the flow to the perforations and the blockage of the flow by the wellbore itself. Because of the orientation of a horizontal well relative to the anisotropic permeability field, perforation skin models for vertical wells that consider these effects, notably the Karakas and Tariq model1, are not directly applicable to perforated horizontal completions. Using appropriate variable transformations, we derived a skin factor model for a horizontal perforated completion that is analogous to the Karakas and Tariq vertical well model. The empirical parameters in the model were determined from an extensive 3D finite element simulation study.

The results of the new model show that the azimuth of a perforation (the angle between the perforation tunnel and the maximum permeability direction, usually thought to be the horizontal direction) affects the performance of perforated completions in anisotropic reservoirs. When perforations are normal to the maximum permeability direction, perforations will enhance horizontal well flow compared with an openhole completion (a negative skin factor). But if perforations are in the same direction as the maximum permeability, significant positive skin will result. The new skin factor model provides a clear guide to the shot density, perforation orientation, and level of perforation damage that is tolerable to create high productivity perforated completions in horizontal wells.
Chelating Agent-Based Fluids for Optimal Stimulation of High-Temperature Wells
Authors: Ali A. Husen A. , Frenier W. W. , Xiao Z. , Ziauddin M.
Published: December 2007

Chelating agents have the ability to complex and sequester many types of metal ions in aqueous solutions. These chemicals have been used extensively in oil and gasfield treatments for stabilization of iron, scale removal, and as stimulation agents. Examples of chelating agents are ethylenediaminetetraacetic acid (EDTA), hydroxyethylethylenediaminetriacetic acid (HEDTA), and nitrilotriacetic acid. In this paper we describe results from laboratory tests and field treatments using chelating agent-based fluids for matrix stimulation of high-temperature sandstone and carbonate formations.

In carbonates we have proven that formulations containing both EDTA and HEDTA will form wormholes at temperatures up to 400°F (204°C). Pioneering work in the late 1990s can be correlated with many of the results, but low-pH formulations of hydroxy chelating agents have unique characteristics that are especially suitable for stimulation of high-temperature carbonates. When tested in the lab at practical injection rates for field applications, chelating agent-based fluids were much more efficient than both mineral and organic acids. Formulations with very low corrosion rates on carbon steel and corrosion resistant alloys (CRAs) were developed for temperatures up to 425°F (218°C).

In sandstones we show that alkaline formulations containing surfactants and hydrotropes are more effective than mineral and organic acids for stimulating formations that are damaged with carbonates and acid-sensitive clays. Laboratory tests to optimize these formulations and field applications in deep, hot gas wells are presented. A gas well in a sandstone formation with a bottomhole static temperature (BHST) of 300°F (149°C) was stimulated with a noncorrosive chelating agent formulation. The well had produced >2 MMscf/D gas while it was completely plugged prior to the chelant formulation treatment.
Natural Gas: The Excruciating Transition
Authors: Oligney R. E. , Economides M. J.
Published: December 2007

Natural gas has gone through an unprecedented roller coaster in 2000 and 2001 which among other things included the collapse of Enron, one of the biggest players in the field. Prices rocketed from $2 to over $10 and then declined to below $3 per Mscf. Yet, fluctuations notwithstanding, the "new" natural gas price is $3.00 to $3.50, both floor and ceiling. The floor, calculated by us, is set by full-cycle costs, which include potential reserves, discovery rates, proved reserves, the activation index by region and well decline rates. The price ceiling is set by liquid natural gas (LNG) imports and Arctic gas. Both require the $3.00 to $3.50 price range.

The problem with a calculated average national equilibrium price of, for example, $3.25 gas is that it is made up of $1 to $10 fluctuations. Even when demand forces natural gas prices to the high levels that were observed in 2001, reservoir physics of the mature United States environment precludes a quick response. Thus, spikes of $10 gas cannot generate new domestic supply.

In a number of our previous writings, we have suggested that the trend toward natural gas as the premium fuel in the near future is not reversible. The key and the excruciating problem is the transition.

We examine in this paper a number of potential sources of natural gas, their limitations and potential. We also present a number of issues, which involve both national policy and rational business decision-making, to take the nation through the transition.

Managing the transition to natural gas is critical to the well-being of the nation and, considering the position of the United States on energy markets, the rest of the world. We finally show in this paper a stark example of the enormous impact of energy supply interruptions on the employment history of the United States, a situation, which may be the harbinger of major future economic hardships if the transition to natural gas is not managed properly.
Compositional Streamline Simulation
Authors: Jessen K. , Orr F. M.
Published: December 2007

Performance evaluation of miscible and near-miscible gas injection processes can be assessed through conventional finite difference (FD) compositional simulation. However, low-resolution compositional simulation is adversely affected by numerical dispersion and may fail to represent geological heterogeneities adequately, and high-resolution simulation is too expensive in computation time. The number of components can be reduced but at the price of less accurate representation of phase behavior.

Streamline methods offer another approach to high-resolution simulation. This paper reports results of combining an analytical, one-dimensional (1D) solution for multicomponent gas injection with a representation of flow along streamlines to capture the effects of heterogeneity. The 1D solution allows any number of components to be present in the injected gas as well as in the reservoir fluid. We report the results from combining the analytical 1D multicomponent solutions with 2D and 3D streamline simulators. A detailed comparison is given between the results of conventional FD simulation and the streamline approach. The comparison demonstrates that the CPU time requirement used in evaluation studies can be reduced significantly while at the same time reducing the adverse effects of numerical dispersion.
Drilling Waste Management: Past, Present, and Future
Authors: Veil John A.
Published: December 2007

The process of drilling oil and gas wells generates large volumes of drill cuttings and spent muds. The American Petroleum Institute estimates that in 1995, about 150 million barrels of drilling waste was generated from onshore wells in the United States alone. Onshore and offshore operators have employed a variety of methods for managing these drilling wastes, depending on what state and federal regulations allow and how costly those options are for the wells in question. In the offshore, the options are limited to discharge, underground injection, and transport back to shore for disposal. Onshore operators have a wider range of options--some wastes are managed onsite while others are removed to offsite commercial disposal facilities. The onshore waste management options employed include landspreading and landfarming, evaporation and burial onsite, underground injection, incineration and other thermal treatment, bioremediation and composting, and reuse and recycling.

Some drilling waste management practices used in the past did not protect the environment and public health to the extent desired and were later prohibited by regulatory agencies. This paper reviews some of those past waste management practices and indicates how wastes are currently being managed. Over time, state and federal regulatory requirements will become stricter, drilling and mud system technologies will advance, and some companies may voluntarily adopt waste management options that have even less environmental impacts that those in use today. The paper also discusses some possible drilling waste management practices that are likely to be employed in the upcoming decade.
Nuclear Magnetic Resonance While Drilling in the U.K. Southern North Sea
Authors: Appel Matthias , Radcliffe Nigel J. , Prabhakar Aadireddy , Bonnie Ron J. M. , Ridvan Akkurt
Published: December 2007

Standard formation evaluation of an exploration well in the UK Southern North Sea was supported by Magnetic Resonance While Drilling (MR-WD).

In this paper we show that even in tight gas sands, MR-WD provides information about porosity and producible fluid fraction, and allows estimation of formation permeability.

This successful introduction of MR-WD technology in a known hard-rock environment illustrates a powerful addition to the logging-while-drilling tool suite.
Applications of a New-Generation NMR Wireline Logging Tool
Authors: Heaton N. J. , Freedman R. , Karmonik C. , Taherian R. , Walter K. , DePavia L.
Published: December 2007

This paper discusses applications of a new-generation, nuclear magnetic resonance (NMR) wireline logging tool. The new design is a multi-frequency, eccentered, gradient-field NMR logging tool with multiple depths of investigation, which are maintained regardless of the hole size and are deeper than those of previous NMR logging tools. The new-generation tool features a high-resolution acquisition mode, making it possible to perform both fluid characterization and thin-bed analysis.

We present the results of MRF* Magnetic Resonance Fluid characterization logging in a range of different environments. MRF acquisition modes comprise suites of spin-echo sequences having sensitivity to molecular diffusion. Simultaneous analysis of an entire suite of data provides depth logs of oil viscosity and fluid saturations measured in the nearwellbore region as well as total porosity, T2 distributions, and permeability estimates.

Several logs acquired in different formations are used to demonstrate the high-resolution capability of the new tool. Data acquired in a test well with known characteristics are used to validate the vertical resolution, precision, and accuracy of the measurements.
A Method for Real-Time Well Clean-up Optimization
Authors: Waskoenig Hans-Heinrich , Langhans Grit , Miljenko Cimic , Heil Matthias , Antink Gerhard Hoog , Toskey Eric
Published: December 2007

A new technique to optimally clean-up wells has been developed. The method employs coiled tubing and pumped nitrogen to provide a controlled lift of the wellbore fluids, a multiphase flow meter to monitor from surface the results, and simulation software to model the process in real-time so that timely operational decisions can be made. This new technique was successfully applied to several challenging nearhorizontal extended reach well completions. The method can effectively clean out perforations and achieve an efficient displacement of the completion fluid out of the well. The control necessary to prevent damaging fragile formations and to minimize the risk of leaving bypassed completion fluid in a horizontal section is provided. The method also avoids the undesirable use of electrical cable in the coiled tubing to monitor the downhole conditions. Real-time surface fluid recovery and downhole nitrogen injection rates and volumes are obtained. Fluid lift simulations performed on-site during the lifting operation are history matched to actual well production data. Immediate adjustments to the lift can be made to optimize the well clean-up.
Relative Permeability Modification Using an Oil-Soluble Gelant to Control Water Production
Authors: Karmakar G. P. , Grattoni C. A. , Zimmerman R. W.
Published: December 2007

Water production in gas and oil wells is one of the major problems faced by the petroleum industry. Polymers and gels can be efficient materials for controlling excessive water production in gas and oil wells. The injection of gelant solutions into the near-wellbore formation can reduce the permeability of the formation to water much more so than to oil. Such gelants are known as relative permeability modifiers. In this experimental study, tetramethylorthosilicate (TMOS) has been used as the oil soluble gelant. TMOS is soluble in the oil phase, and reacts with water to form a semi-solid gel that is capable of modifying the permeability of the rock. As the water is transformed into gel, the permeability of the medium to water is reduced. Due to the increase in volume of the "water phase", the oil permeability is reduced to a lesser extent.

A series of static and dynamic gelation and flow experiments have been performed in test tubes. These were followed by flow tests conducted in transparent glass micromodels to determine the end-point relative permeability for oil and water before and after gelant injection. Our results show that the gel formation depends on the concentration of the gelant in the oil phase, the oil/water ratio, the amount of total gelant solution injected, and the time of flow of the gelant solution into the water phase. It was observed that the volume of gel obtained after gelation increases as the TMOS concentration increases, at a fixed oil/water ratio. The degree of permeability reduction for both oil and water is directly related to the amount of gelant injected. The results we have obtained can be used for pre-screening the efficiency of TMOS treatments.