bluuebunny/crossref_metadata_2025 huggingface dataset:
Efficient Delivery of Bolivian Exploration Well Despite Geological Uncertainty Using an Expert Bit-Selection System
Authors: Balda C. , Pacione M. , Evans H.
Published: December 2007

This paper will discuss the benefits of using an Expert Bit Selection (EBS) system for bit selection and estimated Rate of Penetration (eROP) modeling in the pre-drill, implementation and post well analysis phases of an optimization project for exploratory drilling in the Southwest Basin of Bolivia.

Drilling a vertical wildcat well in the SW Basin thrust belt presented a number of distinctive challenges. To reduce the associated risks, engineers consulted with local geological experts and produced multiple stratigraphic scenarios and likely formation top depths. These scenarios were modeled through regional correlation between offset formations and formation tops. The models were populated with anticipated operating parameters and used in the expert system to make bit selections appropriate for the specific drilling environment.

Constant monitoring of drilling data, cuttings descriptions and comparison of penetration rate with eROP while drilling ensured that the most representative scenario would be identified and appropriate bit recommendations prepared while tripping out of the hole. Additional changes to the EBS system model were made when unexpected lithologies were encountered and sequencing of formations varied significantly from the initial prognoses.

Despite encountering dramatically different formation types and tops from those prognosed, the EBS system helped save the operator 15 days relative to AFE and the 17-½" section (including running the 13-3/8" casing to bottom) was completed without incident. Additionally the number of bits used was 13 – 34 less than used on comparable wells.

Using an alternative analysis, by isolating flat times, the normalized time curve versus AFE showed a 27-day saving for the 17-½" section, which at an average rig cost of US$50,000/day translates into a saving of US$1.35 million.
Evaluation of Inflow Profiles Behind Tubing Using Pulsed Neutron Logs
Authors: Poe B. D. , Butsch R. J.
Published: December 2007

This paper presents the development of a production logging analysis methodology and associated formation inflow interpretation model for wells that may have their production tubing string setting depth below the top of at least the shallowest completed interval in the well. The practice of selecting a tubing setting depth greater than that of the shallowest completed interval in a well is often utilized in wells that produce significant amounts of formation liquids. The tubing string is set lower in the wellbore than the uppermost completed interval in order to assist in liquid unloading of the well.

Conventional production logging tools that utilize fluid velocity measurement devices such as spinners can not be used to measure the wellbore fluid velocities in the annulus of the casing and tubing strings in the well. As a result, the inflow profile of the completed intervals in the well that are shallower than the tubing string setting depth in the well (or in practice, somewhat even lower than the end of the tubing string due to convergence effects) can not be obtained with those devices without first raising the tubing above all of the completed intervals in the well. This repositioning of the tubing string setting depth so that a conventional production log can be obtained for those completed intervals can alter the inflow profile of the well.

In this paper, the description of a mathematical interpretation model that has been developed for reliably estimating the inflow profile of a well in which the production tubing string in the well extends to a well depth greater than the depth to the top of the shallowest completed interval in the well is presented. The production performance evaluation model described in this paper provides a means of determining the inflow behavior of a well of this type, without the need for repositioning of the tubing string so that it is set above all of the completed intervals in the well. The results of this analysis therefore are analogous and equivalent to that which would be obtained with conventional production logging methods if those inflow profile evaluation techniques could be used in wells of this type without repositioning of the tubing string. The wellbore flow measurements that are utilized in this production logging analysis are obtained with Pulsed Neutron logs and are the liquid holdup in the wellbore and the annular or tubular flow liquid velocities. The liquid holdup in multiphase flow in the well is determined using the Inelastic Ratio measurements of a Pulsed Neutron logging device and the annular flow water velocities are directly obtained from the analysis of water flow measurements in the well.
Fluid Flow and Particle Transport Analyses Show Minimal Effect of Annulus Between Horizontal Wellbore and Expandable Screen
Authors: Li J. , Hamid S. , Hailey T. , Simonds R.
Published: December 2007

Proposal

Expandable screens are becoming increasingly more important in sand-control completions because of their exceptional capabilities for providing wellbore support and optimized wellbore geometry. This is particularly important for offshore horizontal wells. Currently, two types of screen expansion technologies exist; i.e., the constant-diameter (fixed-cone) expansion technology and the variable expansion technology. Each approach has its own advantages and disadvantages in terms of deployment, wellbore support, and inflow performance characteristics.

With fixed-cone expansion technology, the industry has had the concern that annular flows between the open hole and screen can lead to transport of formation sands. This phenomenon can lead to localized screen erosion due to partial screen blockage, concentrated flow in unblocked portions of the screen, and finally, failure of the filtration layers. This paper discusses a method that can determine the probability of the above concerns with a model that analyzes fluid flow and particle transport. The forces acting on individual sand particles are modeled to ascertain the particle transport within the annulus and determine annular flow problems. Based on a given production profile that takes into account the frictional pressure losses of fluid in the annulus and in the base pipe, this model can predict if there is any possibility that particles in the annulus will be transported. Using this method, the wellbore (annulus) section in which no particles would be transported can be predicted.

Computational Fluid Dynamic (CFD) simulations were carried out to study the flow distribution in the horizontal wellbore. At a given wellbore location, the percentages of fluid flowing inside the basepipe and in the annulus were calculated. The simulations typically showed that the average fluid velocity in the annulus is an order of magnitude less than the fluid velocity inside the base pipe. The study also showed that if designed properly, a screen with fixed-cone expansion can be used successfully without concern of particle transport and with very limited flow in the annulus.
Single Cutter Impact Tests Investigate Deep-Well Hammer-Drilling Performance
Authors: Green S. , Judzis A. , Curry D. , Black A. , Prasad U. , Rogers J.
Published: December 2007

The use of a percussion hammer can provide high penetration rates through hard rocks when air drilling. The work of this paper was partly sponsored by the US Department of Energy to develop hammer drilling techniques for drilling deep hard rocks, using real drilling muds. Unfortunately, development is complicated because understanding rock breakage and cuttings removal under the dynamic loading conditions of hammer drilling is difficult. Historically, empirical relations have been used to relate hammer blow energy and blow rate with drilling.

This paper presents results of carefully measured single cutter impact—as well as high rate and ‘static’—rock indentation tests under high borehole pressure conditions, using real drilling muds. The results include cutter force-displacement and crater volumes for both first stress wave (initial impact) and long time (quasi static) rock indentations. From this, specific energy for rock breakage (i.e. the energy to excavate a unit volume of rock) can be calculated.

The specific energy values measured in these single cutter impact tests show the rock destruction efficiency that can be achieved by impact loading. They are compared with specific energies measured during full scale hammer and rotary drilling experiments, under relatively similar conditions.

For a given rock type, impact stress, cutter configuration, wellbore pressure, and mud type are shown to be critical parameters. A key observation is that most of the rock breakage occurs during the first stress-wave, and for higher impact stresses above the dynamic confined indentation strength, relatively little additional rock breakage seems to occur.
Surfactant Gel Foam/Emulsion: History and Field Application in Western Canadian Sedimentary Basin
Authors: Gupta D. V. S. , Leshchyshyn T. T. , Hlidek B. T.
Published: December 2007

Surfactant gels were introduced into the Western Canadian Sedimentary Basin (WCSB) as fracturing fluids in 1998. These fluids proved to be successful for propped fracture stimulations in shallow gas wells. About the same time, it was found that surfactant gels could be foamed with nitrogen or emulsified with a high quality (volume fraction) of liquid CO2. Since their inception in the Canadian market, surfactant gel foams/emulsions have been used in coal-bed methane (CBM) and also in the stimulation of deeper, higher temperature applications.

This paper will discuss the use of these fluids in the WCSB as well as the chemistry of the fluids, laboratory conductivity measurements which show proppant pack retained conductivities of greater than 96%, and their application in more than 3,100 oil and gas producing zones. The fluids have been used in a variety of formations and in wells with permeability's from 0.1 millidarcies to 10 Darcies, depths in excess of 3000 m (10000 feet) and bottom-hole temperatures up to 100 °C (212 °F). For water-sensitive formations, foamed surfactant gel fracturing costs are significantly less in comparison to hydrocarbon, CO2, or methanol-based fluids.
Integrating Intelligent-Well Systems Into Sandface Completions for Reservoir Control in Brazilian Subsea Well
Authors: Moreira O. M. , Stacey A. , Anderson A.
Published: December 2007

The ability to integrate intelligent well systems into sandface completions is gaining importance as a critical success factor to economic development of smaller, subsea assets. For these types of assets to be economically viable, multiple zones must be tied together with fewer wells. To optimize production, the zones are often completed and commingled initially, then isolated to eliminate water or gas breakthrough. In many areas, such as the Campos Basin of Brazil where hydrocarbon-producing formations also have a tendency to produce sand, active sand control is also necessary. This paper describes the successful integration of an intelligent completion system into the sandface completion of a subsea well in the Bicudo field offshore Brazil. The well required mechanical isolation of two open-hole gravel packed zones to facilitate flow control. The operator also wanted to eliminate future workovers and use remote control to isolate the lower zone to prevent water breakthrough. Using external casing packers, removable production packers and an intelligent completion system with an advanced, hydraulically activated remote-control sliding sleeve, the resulting shallow-water, horizontal, subsea intelligent completion yielded double the expected recovery rates from the longest horizontal section ever completed by Petrobras.
A Fully Implicit, Parallel, Compositional Chemical Flooding Simulator
Authors: Han C. , Delshad M. , Sepehrnoori K. , Pope G. A.
Published: December 2007

We have developed a fully implicit, parallel, compositional reservoir simulator that includes both a cubic equation of state model for the hydrocarbon phase behavior and Hand's rule for the surfactant/oil/brine phase behavior. The aqueous species in the chemical model include surfactant, polymer, and salt. The physical property models include surfactant/oil/brine phase behavior, interfacial tension, viscosity, adsorption, and relative permeability as a function of trapping number. The fully implicit simulation results were validated by comparison with results from our IMPEC chemical flooding simulator (UTCHEM). The results indicate that the simulator scales well using clusters of workstations. Also, simulation results from parallel runs are almost identical to those using a single processor. Field-scale, high-resolution surfactant/polymer flood simulations were successfully performed with over 1,000,000 gridblocks using more than 100 processors.
Integrated Interpretation of a Rich Data Set From a New-Generation LWD Tool
Authors: Neville T. J. , Faivre O. , Sun H. T. , Weller G.
Published: December 2007

A new logging-while-drilling (LWD) tool combining traditional measurements of gamma ray, propagation resistivity, gamma-gamma density, and thermal-neutron porosity with measurements unique to the LWD arena opens up new opportunities for formation evaluation on LWD. Neutron capture spectroscopy provides elemental concentrations of major rock-forming elements; these can be translated into mineralogy and matrix properties such as matrix density and matrix capture cross section using well-established algorithms.

The combination of continuous matrix properties from neutron capture spectroscopy with conventional gammagamma density and enhanced thermal-neutron porosity measurements, and a new capture cross section measurement provide the means to calculate porosity and saturation directly from nuclear measurements. The use of this multiplicity of direct measurements allows for the calculation of accurate porosity and fluid saturations with reduced uncertainty and subjectivity when compared to traditional triple-combo interpretation.

The accurate clay fraction derived from neutron capture spectroscopy also allows for enhanced interpretation of saturation from resistivity in shaly sands. The availability of two independent saturation estimates from similar volumes of the formation allows for improved confidence in the water saturations obtained.
Mitigating Oil Bypassed in Fractured Cores During CO2 Flooding Using WAG and Polymer Gel Injections
Authors: Chakravarthy D. , Muralidaharan V. , Putra E. , Hidayati D. T. , Schechter D. S.
Published: December 2007

Fractured reservoirs have always been considered as poor candidates for enhanced oil recovery. The fractures provide a pathway for injected fluids to channel through directly from injection to production wells. The interaction between these fractures and the reservoir rock matrix often determines the degree of bypassing during injection of CO2. The use of CO2 as a displacing agent through these reservoirs aggravates the problems of low sweep efficiency due to its high mobility. The microscopic displacement efficiency of CO2 is very high, but the overall displacement efficiency is often hindered by its high mobility that is largely the results of viscosity and density contrasts between the CO2 phase and the reservoir oil and brine phases. In this study, we performed CO2 injection experiments with different injection rates and utilized X-ray CT to determine the saturation distribution along the core and measure oil bypassed during CO2 process in fractured cores. We improved the CO2 sweep efficiency by controlling the CO2 mobility in the fracture. Water viscosified with a polymer was injected directly into the fracture, to divert CO2 flow into the matrix and delay breakthrough. Although the breakthrough time reduced considerably, water "leak off" into the matrix was very high. To counter this problem, a cross-linked gel was used in the fracture for conformance control. The gel was found to overcome "leak off’ problems and effectively divert CO2 flow into the matrix. This experimental results increase the understanding of fluid flow and conformance control methods in fractured reservoirs.
Numerical Simulation of the Storage of Pure CO2 and CO2-H2S Gas Mixtures in Deep Saline Aquifers
Authors: Ozah R. C. , Lakshminarasimhan S. , Pope G. A. , Sepehrnoori K. , Bryant S. L.
Published: December 2007

We have studied strategies for maximizing several phenomena beneficial to large-scale subsurface storage of waste gases such as CO2 and H2S. Numerical simulations using a compositional reservoir simulator were carried out for 10,000 years to understand the flow and long-term storage potential of pure CO2 and CO2-H2S mixtures in deep saline aquifers. Hysteresis in the relative permeability curve results in substantial volumes of gas trapping. Aquifer characteristics such as heterogeneity, dip angle and vertical to horizontal permeability ratio were varied to determine their effect on storage potential and injectivity of a CO2-H2S gas mixture. The opportunity for escape of the gases from the aquifer can be minimized by careful design of injection strategies. One such strategy is to use horizontal wells low in the formation so that all of the injected gases are trapped, dissolved or precipitated before they reach geological seals and/or faults. This allows significantly larger volumes of waste gases to be stored in a given aquifer. Preferential solubility of the H2S in brine reduces the distance H2S travels relative to CO2. Simulations with local grid refinement show that fingering due to buoyancy is mitigated by natural heterogeneity in the aquifer petrophysical properties. Thus the amount of gas trapping observed in coarse-grid simulations is likely to be a reasonable estimate of what can be obtained in the field. Three-dimensional simulations of coupled flow and reactive transport showed that the amount of CO2 sequestered as minerals was small relative to gas trapping and dissolution into brine. However, the mineralization further reduces the already small amount of mobile gas over long periods of time.
Stochastic Modeling of Fluvial Reservoirs: The YACS Approach
Authors: Alapetite J. , Leflon B. , Gringarten E. , Mallet J. -L.
Published: December 2007

This paper describes a novel approach to model fluvial reservoirs. The core of the method lies in the association of a fairway or river bed with the channels to be simulated. A potential field is defined within the fairway. Specifying a transfer function to map this potential field to thickness results in a generating a channel inside the fairway. A residual component is stochastically simulated and added to the potential field creating sinuosity and realistic channel geometries. The degree of deformation is controlled and allows the creation of channels with high sinuosity including oxbows. Conditioning to well data is obtained by applying the inverse transfer function at the data location to derive thickness values which will constrain the simulation of residuals. Fairways are positioned so that all data are taken in account; they can be stochastic if unknown or explicitly entered if identified on seismic data.

The method allows simulating channels which honor both exactly hard well data and channel proportions, following arbitrary shapes guided by fairways. The algorithm is based on sequential algorithms which guarantee convergence and speed; there is no iteration or optimization loop. This new approach can simulate channel, levees, and also lobes; channels can have multiple branches and conditioning a single channel (branch) to multiple wells is also possible.
Horizontal Screen Failures in Unconsolidated, High-Permeability Sandstone Reservoirs: Reversing the Trend
Authors: Arukhe J. , Uchendu C. , Nwoke L.
Published: December 2007

Horizontal screen failures can be serious, resulting in expensive remedial operations including early abandonment, in the extreme case.

Globally, screen failures in horizontal wells completed in loose unconsolidated sandstone reservoirs have become common. Consequently, from completion and longevity perspectives, a high percentage of horizontal wells have not achieved the desired result: sand-free, high sustained-productivity producers. Individual companies have performed studies in this direction, and some are still ongoing. From preliminary data available, however, it has been possible to observe trends and determine the failure mechanisms.

Failure categories highlighted in this paper include wells with significant impaired productions or those completely plugged, representing an overall failure rate of almost 20%. This paper suggests several levels of screen failure: screen collapse or complete plugging, partially plugged screens (poor performing wells) and those producing unacceptable amounts of sand. Other failures include improper installation and economic failures where fixing the problem is possible but costly. Some wells exhibited ‘’early mortality’’, producing sand at production onset.

The study further categorized possible causes of screen failures into three major areas: ➣Screen plugging caused by high-pressure drops across screens, hot spots of localized production, fines and dirty sand.➣Incorrect procedures, materials or equipment selection including trouble installing the screens, corrosion in low spots due to standing acid, generalized corrosion from acids, improper cleanup, ineffective mud removal, ineffective sand control, inappropriate screen selection and erosion.➣Poor reservoir understanding in the areas of grain size distribution, sanding up due to water production, open annular areas due to higher than expected rock strength.

This paper reviews various applications of soft rock completions in horizontal service, along with benefits and shortfalls. The performance characteristics of the various screens relative to each other from the perspective of flow capacity, plugging and erosion resistance are examined. Recommendations based on ‘’best practices’’ being adopted to combat screen failure problems in high permeability reservoirs are also showcased.
Gulf of Mexico Shelf Deep Ultra-HP/HT Completions—Current Technology Gaps
Authors: Hahn D. , Atkins M. , Russell J. , Pearson B.
Published: December 2007

Numerous operating companies are pursuing new and much deeper geologic horizons on the Gulf of Mexico continental shelf. This is a logical expansion of a geographic area with a very mature and well established surface infrastructure. However, as the well depths increase, the wellbore construction and well production operations become much more challenging because ultra-high pressures and high temperatures - HPHT (e.g. 25,000+psi and 450+°F) will then need to be handled and/or managed. The industry is probably able to safely drill these more extreme wells but there are some significant well completion technology gaps that require design and development. The most cost efficient approach to bridge these gaps may be for several companies to collaboratively share in the costs to develop the appropriate equipment for these applications.

This paper demonstrates the need to enhance the industry's capability to actually begin production from these deep ultra HPHT wellbores. The numerous areas that require increased completion capability will be presented in this paper. The production tubulars (casing and tubing) will be a major cost driver as designs will need to address temperature deration of strength, geometric complexity to achieve adequate bore and clearances, corrosion and environmental cracking. Risk analyses and testing will dictate metallurgy, pressure containment, connection capability under compression and bending, and benefits and reliability of cementing. Production packers, subsurface safety valves, and flow control nipples/plugs appear to be the nearest to implementation, but some design and qualification issues still need to be resolved. Current perforating technologies are reaching their limits at temperatures exceeding 450°F, thus require significant attention in their specific application and a quality assurance/quality control (QA/QC) program. The major hurtle for fully rated completion blowout preventors (BOP's) and trees will be the need to redesign the valve stem sealing mechanisms. Finally, both intervention and contingency possibilities, like slickline, pumping services, stimulation, snubbing, etc., are important situations that require additional enhancements to currently available technologies.
Diverse Application of Unique High-Performance Water-Based-Mud Technology in the Middle East
Authors: Al-Ansari A. , Yadav K. , Anderson D. , Leaper R. , Dye W. , Hansen N.
Published: December 2007

A high performance water based mud (HPWBM) system has been used successfully to address a combination of drilling challenges faced in the Middle East. Drilling problems encountered in the area typically include shale instability through pressure transmission effects, swelling clay-stone, bit balling, drill-string accretion, differential sticking over tight gas permeable sands and down-hole losses.

All these challenges can be very difficult to overcome with conventional water based mud (WBM) systems and can prove very expensive in terms of lost mud, lost down-hole tools, non performance rig time, side-tracks or ultimate failure to meet well or section objectives.

The HPWBM system was introduced to provide considerable improvement in WBM performance and also provide an environmentally benign alternative to oil based muds (OBM) while emulating OBM drilling performance attributes. Recent applications in the Middle East have proved that the HPWBM system can be applied as an alternative to OBM, successfully achieving the objectives of the sections while providing drilling performance comparative to OBM.

This paper discusses the technical features of the HPWBM system, gives an outline of previous applications and presents detailed case histories of the more diverse applications of the system and its components in wells in the Middle East, while comparing performance to offsets drilled with conventional WBM and OBM.
An Alternate Approach: Utilizing New PDC Technology for Drilling Deep LNG Wells Delivers Significant Savings for Major Operator in Oman
Authors: Teasdale P. , Riley N. , Mackinnon P.
Published: December 2007

A major operator has been drilling deep liquefied natural gas (LNG) wells for several years in central Oman. These wells are typically drilled vertically, featuring a complex geological sequence, that provides a significant challenge to bit performance.

Historically these wells have been drilled in 90 days with Tungsten Carbide Insert (TCI) bits on packed rotary assemblies down to the 9 5/8" casing shoe and Impregnated bits on turbine assemblies with occasional TCI runs in the 8 3/8" section.

A detailed study of the LNG wells focused on drilling performance in each of the three hole sizes in a typical well profile. The findings suggested that the introduction of new PDC technology was viable over much of the intervals and that significant savings in terms of time and cost could be achieved.

This paper reviews the findings of the study subsequent recommendations and the application of advanced PDC technology and stable PDC bit designs. The resulting improved performance is demonstrated by examples shown from two separate fields in central Oman where significant savings were achieved in terms of both rig time and cost per meter.

The collaboration between the Operator, rig contractor, bit vendor and other service companies was necessary to provide the platform for a successful operation.
Next Generation Parallel Computing for Large-Scale Reservoir Simulation
Authors: Fjerstad P. A. , Sikandar A. S. , Cao H. , Liu J. , Da Sie W.
Published: December 2007

This paper describes application of Project INTERSECT, a next generation highly scalable reservoir simulator on real large scale field models. High resolution reservoir simulation is required to better define and describe fluid flow and enable improved field development and tactical operational planning. Massively parallel computing techniques overcome limitations of problem size and space resolution. This paper demonstrates that large-scale simulation models can be performed on commodity hardware taking advantage of evolution in multicpu hardware architecture and software engineering. This allows both geologists and reservoir engineers to include more realistic geologic and engineering detail for better and more reliable production optimization.

Intense computer simulation is essential for effective reservoir management. The advances in reservoir characterization techniques and the industry drive towards the ‘smart oilfield’ with rapid model updates will require more efficient model processing to achieve timely field operational decisions. Parallel reservoir simulators have the potential to solve larger, more realistic problems than previously possible. The size and application of reservoir simulation problems have been limited by the availability of computing hardware, reservoir simulation architecture and of solution methods for solving large-scale heterogeneous problems. The next generation reservoir simulator demonstrates that key modeling challenges has been overcome by a software architecture and capability to model more realistic subsurface and surface models.

Applications of the new reservoir simulator illustrates how typical reservoir engineering options such as local grid refinement, local grid coarsening, multilateral wells and aquifer modeling affect the overall parallel performance and scalability using highly heterogeneous large-scale models. Application of new modeling techniques highlight increased accuracy of modeling results and more reliable field development planning and reservoir management decisions.
Dynamic Underbalanced Perforating System Increases Productivity and Reduces Cost in East Kalimantan Gas Field: A Case Study
Authors: Minto D. , Falxa P. , Manalu D. , Simatupang M. , Behrmann L. A. , Kusumadjaja A.
Published: December 2007

New gas wells at Tunu field in East Kalimantan are normally perforated using the extreme underbalanced (EUB) technique, in which a large static pressure differential between the wellbore and formation, or initial underbalance, is set before the gun is fired. This requires an operation to unload wellbore liquid, a wireline operation to set an anchoring tool, and several slickline operations to run and retrieve the gun string. The required degree of underbalance depends primarily on rock properties such as permeability, porosity, and strength.

A new approach produces a well dynamic underbalance (the transient underbalance just after creating the perforation cavity). By basing the job design on the properties of the reservoir, wellbore, and gun string, the technique consistently minimizes perforation damage and thus maximizes productivity. This technique is based on recent single-shot perforating experiments that show that it is the maximum dynamic underbalance—not the initial underbalance—that governs perforation cleanup. The wellbore pressure was found to vary considerably during the first half-second after the charges were detonated. This variation in wellbore pressure can be manipulated to give a large dynamic underbalance.

Perforating with the new technique and electric wireline was performed on 10 wells in the field. Software that considered wellbore geometry, fluid, gun-string selection, and reservoir properties was used to design a specific gun-string configuration and to predict the productivity increase contributed by the underbalance. The jobs were performed smoothly with significant cost savings compared to conventional EUB operations and yielded an increased productivity. Details of the perforating jobs with the new technique will be described, including a cost reduction of approximately 40% and a significant production increase. Testing revealed an average skin value for four wells of −0.29, versus the average skin of 4.73 from 35 conventional EUB perforating jobs executed during the multi-year interval from 2000 to 2004.
Kuwait Oil Company Sets Drilling Record Completing the Zubair Section in One Run
Authors: Al-Saeedi M. J. , Al-Mutairi B. , Al-Ajmi H. S. , Sharma M. , Swadi M. , Tyagi S.
Published: December 2007

Drilling deep exploratory wells in Kuwait presents a number of distinctive challenges. The 16" hole section is particularly demanding because it must be drilled through hard interbedded formations including the Zubair sandstone, Ratawi shale, Ratawi limestone, Minagish limestone/dolomitic limestone, Makhul limestone/shale and Hith anhydrite.1

Historically, 16" roller cone bits were used to drill the float equipment and several hundred feet of Zubair in order to get the stabilizers out of the casing. Several such wells have been drilled in North Kuwait with the best case requiring three PDC bits to complete the section subsequent to the roller cone run. The main challenge has been the highly abrasive Zubair formation with UCS in the 12,000–15,000 psi range.

Traditionally, drilling abrasive formations with PDC has been challenging even in smaller hole sizes (8-1/2" etc).2 However, as hole size increases torque response is magnified increasing vibration issues. In this application, vibration is further amplified by variations in formation hardness. These factors make efficiently drilling the Zubair with PDC a serious challenge. The operator required new PDC bit and cutter technology.

A team was assembled that analyzed PDC technology using numerical models, laboratory and field tests. Engineers focused on the bit frame/cutting structure, and cutter design. Cutters diamond table properties were evaluated in an effort to increase durability and wear resistance. The result is a tougher, more abrasion-resistant cutter capable of maintaining an efficient edge in the hard/abrasive Zubair sand.

Patented depth-of-cut control (DOCC) technology provided smoother, more stable drilling through the interbedded formations. By limiting the unnecessary depth-of-cut of PDC cutters, the amount of torque generated can be effectively controlled. Penetration is managed by adjusting cutter exposure from the bit body and providing a load-bearing surface. Laboratory testing proved how DOCC technology maintains bit aggressiveness needed and limits reactive torque as more weight is applied or as softer formations are encountered. The threshold for bearing engagement is precisely adjusted for each application. This minimized vibration when transitioning between formations while optimizing the ROP advantage of a PDC bit.

Utilizing the new bit design, the operator drilled the entire Zubair 16" interval in a single run for the first time and was able to cut drilling costs by eliminating several trips for new bits and the up-front expense of the extra downhole tools. The authors will discuss how the new technology cut costs and increased drilling efficiencies.
Subsurface Buoy Configuration for Rigid Risers in Ultradeep Water
Authors: Franciss R.
Published: December 2007

The Exploration and Production Department of Petrobras asked the R&D Center the development of a production system for 1800 m water depth, in Campos Basin, which would allow the installation of Steel Caterany Risers (SCR) in the starboard side of a production platform. The subsurface buoy concept was chosen as one of the alternatives. This concept has being developed since the preliminary studies conducted in the first phase of JIP Deepstar.

This concept has an advantage of uncoupling the movements of the platform from the risers, reducing the loads due to the risers in the platform and allowing the installation of this system before the installation of the production vessel, anticipating the production of the field.

This article shows the main characteristics of the buoy, its sizes, results of structural analyses and installation procedures for a buoy which sustains 14 SCR and 5 umbilicals in one side and 14 flexible jumpers and the same 5 umblicals in the opposite side.

This concept was tested in two model test tanks, where it was verified that this concept is feasible. Also, information related to a field trial with a prototype installed in Brazilian waters will be presented.
Technological Challenges for the Development of Ultradeep Water Fields
Authors: Saliés J. B.
Published: December 2007

The paper will present the main drives that PETROBRAS has to overcome the challenge of producing in water depth up to 3000m. It presents also the PROCAP-3000, the in-house Technological Program on Ultra-Deepwater Exploitation System, and its main projects developed to be able to achieve the goals. The paper presents in adition the major challenges in the following areas: anchoring, drilling equipment, risers, boosting, and subsea equipment. The main projects of each area will be discussed, the main results presented and the challenges pointed. Petrobras technical staff believes that the above technical areas and the chosen projects, to be presented, play a key-hole in ultra-deepwater production, not only in Brazil, but also all over the word in deepwater developments.
The Offshore Heavy Oil Development Challenges in Brazil
Authors: Trindade W. L. , Branco C. C. M.
Published: December 2007

The largest accumulations of heavy oil and bitumen under development in the world are located in Venezuela and Canada1. So far, Canada and Venezuela have developed technologies that make it technically and economically feasible to develop these accumulations. The successful thermal methods as steam injection, combustion in-situ and its variations applied in the onshore heavy oil projects have severe limitations to be applied in offshore deep waters. The technological and logistic aspects of the offshore environment make these methods unsuitable if considering the current technologies.

Nowadays, cold production is the only method that could be applied for offshore fields located in deep waters. Even if this technology is applied, it should have some limitations. Unlike the cold production in operation today in Venezuela and Canada, where sand is produced with oil, offshore sand production would be prohibitive due to the high costs of processing or transporting the sand to shore.

The crude production in Brazil is increasing and more and more heavy oil has been produced. In addition, large resources of heavy oil have been discovered during the last 6 years and are under evaluation. In this scenario, the development of technologies that improve the economics of such discoveries is critical for the country to reach and maintain the so aspired self-sufficiency in petroleum.

This paper will summarize the planned path to overcome the challenges related to the exploration, development, production and marketing of the offshore heavy oil in Brazil.
Real-Time Azimuthal Laterolog Image Interpretation for Successful Horizontal Drilling in a Carbonate Reservoir in the U.A.E.
Authors: Ribeiro M. T. , Hendrawan I. , Karrani S. , Griffiths R. , Greiss R. -M. , Chakravorty S. , Bazara M. , Sirum B.
Published: December 2007

Achieving the objectives of drilling horizontal wells is greatly dependent on accurate placement of the drainhole in the reservoir. Careful pre-job planning using offset well data and seismic maps helps to reduce the uncertainty to some extent. However, the unpredictability of structural and stratigraphic variation between the planned and offset wells and uncertainty inherent in seismic data are always associated with horizontal well planning. The formation dips computed from seismic and offset wells are therefore prone to some degree of error.

Advances in real-time data transmission technology have made it possible to transmit image data uphole while drilling, through improving the robustness of the real-time signal, signal bandwidth and data compression. Logging-while-drilling (LWD) real-time azimuthal resistivity images can be used for accurate estimation of the dip and strike of formations intersected along the well trajectory. In addition, structural surprises such as faults can be detected, and remedial actions taken immediately. Such information is of great value in making geosteering decisions while drilling into reservoirs within structurally complex geology or in an area with sparse geological information. Using image data, trajectory adjustments can be made during drilling yielding optimal well placement.

We descibe the use of real-time image interpretation during the drilling of two horizontal wells within a block bounded by major faults on the north and south, with a series of smaller associated faults, anticipated but not confirmed prior to drilling from existing data, in a carbonate field in United Arab Emirates. The image data provided crucial input to guide the well trajectory through the target reservoirs resulting in the wells objectives being achieved. In addition, the image data clarified the regional geology of the area around the wells, thus helping to update the geological model for better description of the structurally complex reservoir.
New 4 3/4" Rotary Steerable System is Combined With a Performance Drilling Motor to Reduce Risks Associated While Rotary Drilling With Small-Diameter Pipe
Authors: Kellas R. , Ruszka J. , Gruenhagen H.
Published: December 2007

Building on the application's success in larger diameter holes, rotary steerable drilling is becoming an established drilling method in 6" hole sections. Rotary drilling in these smaller hole sizes does, however, bring with it some concerns. These include the requirement for high surface rotary speeds to achieve acceptable penetration rates. As a result, these rotary systems may need to place very high dynamic loads on small diameter drillpipe. A new rotary steerable system has been developed which integrates a high performance drilling motor into the bottom hole assembly. By driving the drill bit with the downhole motor, drillpipe rotary speeds and weight on bit can be reduced while simultaneously increasing rate of penetration. This reduces the stress on the drill string and increases drilling performance. This paper describes this new system illustrated with results from real wells.
Quantifying Remaining Oil by Use of Slimhole Resistivity Measurement in Mixed Salinity Environments - A Pilot Field Test
Authors: Al-Sunbul A. H. , Ma S. M. , Al-Hajari A. A. , Srivastava A. , Ramamoorthy R.
Published: December 2007

Quantifying remaining oil in waterflooded reservoirs is critical for successful reservoir management. For wells with narrow producing tubings, the slimhole induction tool is used because of its deep depth of investigation (DOI). Mixed formation water salinity is characterized using bottomhole samples. Ideally, running an induction tool requires non- or low-conductive borehole fluid uniformly distributed in the borehole. This may not always be achievable under production conditions. In this study, the following were investigated: The slimhole induction tool was first tested in a newly drilled well and its measured data were compared with that of the standard induction log.The tool was run in a borehole under both flowing and shut-in conditions. In this case, the effect of borehole fluid distribution was evaluated.The multiple DOI capabilities of the slimhole tool were used to study the phenomenon of borehole fluid reinvasion during both flowing and shut-in conditions.

From this study, the following were concluded: Slimhole induction measurement agrees well with standard induction measurement.Mixed formation water salinity can be characterized using bottomhole samples and production logs.The following borehole characteristics affect shallow DOI measurements, but not deep DOI measurements: Borehole rugosity.Borehole fluid contact and conductivity.Borehole fluid re-invasion.

Guidelines for running slimhole induction log and collecting bottomhole samples for quantifying remaining oil in mixed salinity environments are summarized based on experiences learnt from this pilot field test of more than 30 wells.
Circulating Usage of Partially-Produced Fluid as Power Fluid for Jet Pump in Deep-Heavy-Oil Production
Authors: Chen S. , Li H. , Zhang Q. , He J. , Yang D.
Published: December 2007

Jet pumping driven by light oil is one of the preferred lift methods for producing heavy oil in a deep heavy oil reservoir. Generally, the amount of light oil is too large to be accepted. One solution of reducing the amount of light oil is that partial produced fluid can be combined with the light oil at any reasonable ratio and then the produced fluid-light oil mixture is reinjected into the well as the power fluid. In this case, viscosity of the mixture keeps increasing and eventually reaches its equilibrium value, which is found to be a function of the reservoir oil viscosity, the light oil viscosity (VLO), the ratio of light oil (RLO) in the mixture (volumetric percentage) and the ratio of the well rate to the diluent rate (M ratio). Thus the optimal ratio of light oil in the mixture can be determined by using an iterative algorithm. All of the above-mentioned parameters result in a change of the viscosity of the produced fluid-light oil mixture and the pressure loss in the production string, especially the VLO and the RLO. A field application example shows that the amount of the light oil used can be reduced by more than 50%.
An Innovative Application to Reduce Petrophysical Uncertainty in Reservoir Monitoring: Case Studies from Giant Saudi Arabian Fields
Authors: Eyvazzadeh R. Y. , Kelder O. , Phillips C. , Hajari A. A.
Published: December 2007

Reservoir monitoring requires an accurate assessment of hydrocarbon saturation. As oil fields mature, reducing uncertainty in this parameter can yield major economic benefits in field development and reservoir management.

Recent advancements in resistivity tool design and enhancements in pulsed neutron and NMR tools have expanded the scope of petrophysics in reservoir monitoring projects. Optimal utilization of these technologies requires an understanding of the uncertainties that are associated with these measurements in different types of environments.

A new application has been developed that uses numerical analysis to compute the range of uncertainties inherent in petrophysical analysis. These uncertainties are then used as guidelines to optimize data acquisition.

This methodology defines petrophysical uncertainties on a foot-by-foot basis; consequently decisions are based on prior knowledge of the uncertainty of two of the most important petrophysical parameters, water saturation and porosity.

Several wells have been used in this paper to demonstrate the utility of this application and how this analysis is used to design cost-effective logging programs. Even though this technique can be used with any logging measurements, the focus of this paper will be on resistivity and pulsed neutron devices which are widely used in reservoir monitoring. The examples will show how quantifying uncertainties of key petrophysical parameters reduces reservoir management risk.
Gelled Oil: New Chemistry Using Surfactants
Authors: Samuel M. , Nasr-El-Din H. A. , Jemmali M.
Published: December 2007

Water-based fluids can damage some sandstone formations due to various reasons including clay swelling, emulsions, water-block, and wettability alternations. Oil-based fluids are less damaging than water-based systems to the hydrocarbon bearing formations. Conventional gelled oils (GO) have numerous limitations; however, they are used in formations that are highly sensitive to water. Aluminum carboxylate technology has been used for several decades, aluminum phosphate ester, however, has remained the preferred gelled oil system for the last thirty years.

This paper describes the development of novel surfactant-based gelled oil (S-GO). This new technology uses surfactants to develop the viscosity of diesel. Unlike conventional gelled oil systems, this gelled oil is not sensitive to the nature of base oil or additive concentrations.

The S-GO system, with an order of magnitude higher low shear viscosity, has much better solids suspension characteristics. This cleaner fluid also exhibits low friction characteristics, allowing pumping at higher rates. These unique features make the new S-GO system highly attractive for fracturing, frac-packing, sand control, coiled tubing cleanouts, and as kill pills. This fluid system can be used for applications up to 300°F.