bluuebunny/crossref_metadata_2025 huggingface dataset:
Reservoir-Based Fracture Optimization Approach
Authors: Soliman M. Y. , Byrd Audis , Walters Harold , Weijers Leen
Published: December 2007

A new methodology to obtain the optimum fracture treatment design for a wide range of reservoir conditions has been developed and successfully implemented. The approach discussed here significantly reduces the time required to evaluate an optimum design and limits the materials considered to only those that are appropriate for the reservoir conditions. These improvements make it an ideal methodology for real-time re-design of fracture treatments after feedback from minifrac data has been implemented.

This innovative fracture design methodology has capability to determine appropriate fracture conductivity and an economic optimum fracture length while reconciling these with actual fracture growth behavior in the reservoir. The technique incorporates the following simple, automated steps: Selects the most cost-effective fluid that will meet a minimum apparent viscosity requirement at a specified shear rate and temperature condition from a large industry fluid library to ensure that the proppant will be placed within the pay zone.Selects a proppant that will provide the required fracture conductivity at the cheapest cost from a large industry library.Determines the proppant concentration that is required at the wellbore to achieve a user-specified dimensionless conductivity criterion for a range of fracture lengths.Evaluates economic criteria such as net present value (NPV) and return on investment (ROI) for different fracture lengths by comparing fracture treatment cost and revenues from production response.Determines the optimum fracture conductivity profile that will have a uniform pressure drop down the fracture. The conductivity is adjusted for potential losses from non-Darcy and multi-phase flow, gel damage, embedment, and other proppant damage effects.Iterates a fracture treatment schedule that will result in the best fit of the optimum conductivity profile.

The methodology can help optimize fracture treatments in any type of environment. The technique is simple and can be run quickly in a real-time environment after a minifrac is conducted to make changes to the propped fracture treatment. The procedure has been implemented in a commercially available fracture design program.
Mitigating Vibration in Bi-center Drilling Programs
Authors: Lapierre S. G. , Seiler N. , Chen D. C-K
Published: December 2007

Despite extensive investigation by the drilling and research community, vibration-related bottom-hole-assembly (BHA) failures are still common today. There are many theoretical forms of vibration that have been described in industry literature. Having to address multiple forms simultaneously, vibration mitigation procedures are often overly complex and ineffective.

An extensive study of high-resolution vibration data was undertaken to identify primary forms of destructive motion. Consistencies in BHA behavior were identified from this study and revealed that specific BHA's regularly demonstrate fundamental vibration tendencies in specific environments. As a result, a more focused procedure for corrective action has been adapted and implemented. This procedure has been proven effective without significant negative economic impact to the drilling operation.

This paper discusses the findings of the study. More specifically it addresses the destructive motion of bi-center assemblies. Data from two field examples will be highlighted for practical application.
Specialized Rig-Crew Training Produces Results for New Technology Drilling Rigs
Authors: Plageman Richard A. , Milliren Scott A. , Blackman J. D.
Published: December 2007

This paper describes a successful training program that bridged the gap between machine capabilities and human skills. The program was conducted in support of a land-drilling rig construction project utilizing leading edge technology in rig components and manufacturing techniques. The targeted training was designed to accelerate the learning curve and provide the rig crews a foundation of skills and knowledge that allowed them to excel beyond the company and industry expectations. The curriculum was developed in part from organizational learnings taken from previous new-build programs and from equipment manufacturers' recommendations and expertise.

The combined effect of focused training, organizational learning, and leading edge technology has lead to superior performance in the field. To date, the Total Recordable Incident Rate (TRIR) is 76% lower than comparable, in-house, new-build programs. Likewise, turnover is 70% lower than the past projects. Out of 169 wells drilled by these new rigs, 70% of all wells are below and 6% are on target with the customer's estimated drilling time.
A Deepwater Well Construction Alternative: Surface BOP Drilling Concept using Environmental Safe Guard
Authors: Simondin A. , MacPherson D. , Touboul N. , Ragnes G.
Published: December 2007

Over the recent years, the oil industry has been drilling wells in ever increasing water depths. Drilling these deepwater wells is performed under specific conditions namely a combination of extreme thermodynamic conditions (low temperature and high external pressure at the mud line level) and a narrow margin between pore pressure and fracturing pressure. These conditions lead to a number of drilling difficulties, especially in terms of well control.

Traditionally, these challenging wells are drilled using a sub-sea BOP stack connected at the mud line with a low-pressure riser to the surface. From a well control point of view, this configuration presents several limitations: BOP closing time may be long enough to allow part of the influx to migrate inside the riser, long kill and choke lines add significant friction losses which sometimes jeopardize the kick control, BOP components are subject to extreme thermodynamic conditions and therefore are prone to frequent failures which increase drastically the rig NPT.

In an attempt to overcome the drawbacks of using a sub sea BOP stack and reduce the costs associated with an expensive rig package, the industry developed a technique using the BOP stack on surface in a "jack-up type" configuration and a high pressure drilling riser. Primarily used in the Far East, this technique presents certain limitations, the main one being the absence of a secondary barrier at or just below the mud-line in case of riser failure.

Total was considering to use this technique in 2000m water depth on its recently-acquired Donggala deepwater block, offshore Mahakam straight, Indonesia. A Quantitative Risk Assessment on surface BOP stack drilling was performed. This highlighted the necessity to have a shut-off device at the mud line level in order to reduce the environmental impact in the event of riser failure. Total, in association with Cameron, designed and developed this sub sea shut-off device (hereafter referred to as ESG – Environmental Safe Guard) and with Transocean upgraded a rig to allow safe and efficient drilling on the Donggala block.

This paper outlines the development of the ESG in parallel with the required riser design and well architecture as an alternative to deepwater well construction. An operational feedback on the successful running of the ESG is provided.
Drilling Riser Management for a DP Drillship in Large, Rapidly – Developing Seastates in Deepwater
Authors: Brekke James N. , Soles Julian , Wishahy Momen A. , Stahl Matthew
Published: December 2007

In early 2003, the Glomar Jack Ryan dynamically-positioned drillship drilled a well in the Great Australian Bight in 4308 feet of water. This well was unique in that retrieval of the long riser was required in advance of large, rapidly-developing seastates. Accurate seastate forecasting and on-site measurements were key elements provided by the operator to ensure that enough time was allowed to have the riser pulled and on deck in case well-specific operating criteria were to be exceeded. These seastates were established based on discussions between operator and drilling contractor personnel supported by riser analysis results. Riser recoil analysis was a governing factor so extensive work was carried out to investigate the potential for damage to the BOP stack and slack in the tensioner lines in case of an emergency disconnect.

The subject well was the first drilled by a dynamically-positioned drillship in the Great Australian Bight since 1980. On this well, drilling operations were interrupted even more frequently than they would be otherwise as the well timing extended into the higher seastates of Australia's winter season. In the end, the well was successfully drilled despite encountering several instances in which the significant wave height was about 8 meters (26 feet). In each of these encounters, the riser had been pulled and was on the deck, as was called for by the riser management plan. This paper presents an overview of the riser management carried out for this well.
Drilltronics: An Integrated System for Real-Time Optimization of the Drilling Process
Authors: Rommetveit Rolv , Bjørkevoll Knut S. , Halsey George W. , Larsen Hans Freddy , Merlo Antonino , Nossaman Leslie N. , Sweep Miles N. , Silseth Knut Martin , Ødegaard Sven Inge
Published: December 2007

Drilltronics is the project name of a new and innovative system for drilling automation and simulation. The concept uses all available drilling data (surface and downhole) in real time to optimize the drilling process. If a sensor is failing (PWD for example) then advanced models mirroring the drilling process will calculate the parameter missing (pressure at the PWD sensor position). The system is composed of the following elements: Software modelling with algorithms that reflect the wellbore behaviour and its interaction with the drilling equipment. Currently under development are transient flow and heat transfer models, a drillstring torque and drag model, weight on bit optimization, and stick/slip analysis.The models are driven in real time by drilling data that are logged at high acquisition rate. The system is continuously calibrated through analysing the data with advanced filtering techniques.Real-time diagnosis of the drilling process is obtained from comparing measured data with model predictions. This makes up a basis for continuous adjustments to the drilling strategy.An integrated drilling simulator is developed by linking the modules together, and combining it with an ROP model. This can be used for pre-planning, sensitivity analysis during drilling, post-well analysis, and training objectives.Selected, critical sub-operations will be automated for fast and reliable reaction, e.g. automatic control of the drawwork based on dynamic surge and swab calculations, and automatic detection and first action after easily recognised symptoms on hole problems like pack off or stuck pipe.

In order to realize the full potential of Drilltronics, surface and downhole drilling data must be available in real time. The drilling equipment will need to be computer controlled with an interface that supports automatic responses to the model's analysis.
Advances in API/ISO Oil Mud Chemical Analysis Field Procedures
Authors: Smith Martin V. , Morton E. K. , Pless Marvin L. , Ray Randy , Shumate Thomas , Toups John
Published: December 2007

Oil-based and synthetic-based drilling fluids are important to the industry because they provide excellent performance under the most difficult drilling conditions. To maintain the integrity of these systems, engineers depend upon field test procedures contained within API RP 13B-21 (ISO/FDIS 10414-22). An API Work Group has recently improved these procedures by enhancing reproducibility and substantially reducing standard deviation. This paper will describe the methods and data used to achieve these significant gains.
Barite-Sag Management: Challenges, Strategies, Opportunities
Authors: Scott Paul D. , Zamora Mario , Aldea Catalin
Published: December 2007

Barite sag continues to be a recurring, potentially serious problem on many directional wells. Despite concerted efforts by the drilling industry and early progress, recent continued improvements in sag mitigation have been limited. Sag is a particular problem on HTHP wells and in deepwater wells where ECD management is required. These wells pose difficult drilling conditions where drilling practices may offset sag-management advancements.

The sag "magic bullet" has thus far been elusive. This is understandable since sag is affected by many parameters and their interactions are difficult to quantify. While the importance of mud rheology is well known, attempts to find the key rheological parameter have not been completely successful. Furthermore, lack of industry standards to measure and report barite sag has limited the availability of usable field data. Sound engineering strategies and guidelines have helped, but clearly more developments are needed.

The primary objectives of this paper are to (a) examine key barite-sag challenges, (b) characterize current best practices, and (c) discuss strategies, opportunities, and active programs for step improvements. Recent barite-sag case histories from the Gulf of Mexico, West Africa, and Atlantic Canada are included to set the proper perspectives.
Modeling of ECD in Casing Drilling Operations and Comparison with Experimental and Field Data
Authors: Diaz H. , Miska S. , Takach N. , Yu M.
Published: December 2007

Three modeling approaches to the determination of equivalent circulating density (ECD) in Casing Drilling1 operations are considered in this study; viz., hook-load measurements, pump-pressure measurements and conventional hydraulic models. The bottom-hole pressure is obtained by adding the calculated annular pressure losses to the hydrostatic pressure. Since the annular clearance is very small in casing drilling, a narrow-slot flow approximation model is adopted that takes into account the effect of pipe rotation. A Yield-Power-Law (YPL) drilling fluid is considered in this study.

Results from each of the three approaches are compared with experimental and field data. The differences between the calculated and measured bottom-hole pressures (hence ECD) are within a range of about ±8%. In terms of the frictional pressure losses in the annulus, this range increases to about ±60% in some instances.

It is shown that pipe rotation plays an important role in determining ECD. The experimental data indicate an increase in the annular pressure losses with increasing pipe rotary speed. The hook-load measurements correlate well with flowing bottom-hole pressures.
Cementing Deepwater, Low-Temperature Gulf of Mexico Formations Prone to Shallow Flows
Authors: O'Leary Jim , Flores Juan Carlos , Rubinstein Paulo , Garrison Greg
Published: December 2007

Shallow gas and water flows are a major concern when cementing deepwater wells in many Gulf of Mexico fields, often requiring expensive remedial work, premature well abandonment and respudding. Entire templates can be compromised if a single cement job on surface pipe fails to provide zonal isolation from the shoe up to the mud line.

Traditionally, compressible fluids (mainly foamed cements containing nitrogen) have been used to mitigate shallow-flow hazards in the Gulf of Mexico1. The disadvantages of these systems include safety concerns, complicated logistics, lack of reliability, placement problems, and lack of confidence in long-term cement integrity.

As an alternative to standard energized fluids, special cementing systems based on packing volume fraction and ratios of sized particles (particle-size distribution or PSD systems) have been used with success in water depths exceeding 6,000 ft in the Gulf of Mexico. This paper provides case histories and discusses the use of these innovative systems for deepwater situations. These systems are specially designed to provide optimized gel and compressive-strength development in low-temperature environments while allowing the thickening time to be tailored to any wellbore geometry. Slurry volumes from 1,500 to 2,500 bbl have been pumped without incident. The intrinsically low permeability and porosity of these systems at both the slurry and set-cement stages provide resistance to external attacks and influx of water or gas. In addition, these systems are tested and pumped using standard equipment, completely avoiding the complications of energized fluids; extra personnel are not required.
Understanding Torque: The Key to Slide-Drilling Directional Wells
Authors: Maidla Eric , Haci Marc
Published: December 2007

An in-depth study of surface torque and its effect on drillstring and bit movement has led to the development of automated technology for optimizing directional drilling with a downhole motor/measurement while drilling (MWD) system. By assimilating surface torque with downhole bit and drillpipe behavior, the technology allows drillers to maximize drilling efficiency and improve wellbore quality (due to less trajectory tortuosity) during the sliding part of the drilling process. This paper describes this proprietary1,2,3 surface system and how developers used torque control to optimize slide drilling without introducing new equipment downhole.

The new technology integrates surface and MWD data to provide the following benefits in the sliding mode:

Improved ROP and horizontal reach capability Improved tool-face correction while drilling Improved well trajectory Improved motor life (less stalling) Quick and accurate tool-face orientation No lost-in-hole exposure Time savings from switching from rotating to sliding without coming off bottom; faster tool-face orientation; overall performance optimization (as listed above)
Drilling Fluid Affects MWD Magnetic Azimuth and Wellbore Position
Authors: Torkildsen Torgeir , Edvardsen Inge , Fjogstad Arild , Saasen Arild , Amundsen Per A. , Omland Tor H.
Published: December 2007

The drilling fluid may degrade the accuracy of magnetic azimuth and borehole position significantly so that it complicates the drilling operation and reduces the possibility to hit the planned targets. As an example: Azimuth is distorted up to 5° because of the magnetic properties (susceptibility) of the drilling fluid; and the wellbore is displaced 50 meter in one of the analyzed survey sections.

Survey data from 30 well sections in the North Sea and the Norwegian Ocean are analyzed in order to see whether the weight material in the drilling fluid may affect the magnetic characteristics for the drilling fluid. The cross-axial magnetic field intensity is attenuated more when applying ilmenite instead of barite as weight material. Another significant finding is that the attenuation is stronger in 12 ¼" sections than in 17 ½" and 8 ½" sections.

Laboratory experiments also indicate that drilling fluids with barite are less susceptible than those with ilmenite, and that fresh fluids are more favourable than used fluids. Attenuation factors for cross-axial magnetic components, which are derived from laboratory measurements and a simplified model of the downhole conditions, become much lower than those derived directly from the survey data. This contradiction is explained by some physical and operational conditions.

Guidelines have been established for how to control, reduce and eliminate the negative effect on the wellbore positions. The precautions and actions, which are presented, are dependent on the composition of the drilling fluid, the drilling operation, the wellbore directions, the magnetic interference sources, the accuracy of the geomagnetic reference field and the requirements for wellbore position accuracy and reliability.

The ultimate method for getting around this problem is to measure azimuth with a gyroscopic tool. However, multi-station analysis and corrections of magnetic survey data is also a satisfactory solution when certain operational and geometrical requirements are met.
A Step Change in Drilling Efficiency: Application of New Technology in the Alpine Development Field
Authors: Alvord Chip , Noel Brian , Johnson Vern , Handley Ron , Egedahl David , Cribbs Eric , Smith Lee
Published: December 2007

In the Alpine Development Field of western North Slope, Alaska, application of new technology throughout the continuous drilling of more than 70 horizontal wells has produced an impressive step change in drilling efficiency. This step change is demonstrated clearly by real time cost savings and a significant reduction in drilling times even as the wells have become more challenging both in length and complexity.

Analysis of the extensive Alpine Development Field database of over 1,000,000 feet of hole drilled to date reveals how introduction of new technology and optimized operating parameters in the past two years has increased drilling efficiency by 17%.

Noting economic and environmental issues driving the need for increased efficiencies, the paper addresses the factors that most directly contributed to achieving that goal. These include: comprehensive well planning; optimization of rig capabilities, mud program and operating parameters; and "point-the-bit" rotary steerable technology matched with advanced technology PDC bits.

Highlighted are specific performance achievements in the 8 ½" hole section, a key driver for increasing efficiencies. This interval, which can exceed 10,000 feet, is drilled using the rotary steerable system, allowing utilization of 4" drill-pipe in both 8 ½" and 6-1/8" hole sections for significant time savings through management of both ECDs and standpipe pressure.

Planning/performance of rotary steerable runs, record ROPs achieved, and new bit design technology are detailed, and application and limitations of the new technology are clearly defined through a description of "lessons learned" in achieving this step change in performance.

Finally, economic analysis shows the significant savings realized to date, and estimates savings over the course of the remaining 20 planned wells to exceed four million dollars.
The Effect of Hole Curvature on the Wellbore Pressure Loss Prediction for Highly Tortuous Ultradeep Wells
Authors: Samuel G. Robello
Published: December 2007

Drilling operations in deep and ultra-deep water are increasing around the world. The development of these substantial prospects is very challenging and requires the integration of knowledge with prudent designs at different stages of the well development. However, the cost premium imposed by deep and ultra deepwater wells are higher and many of the discoveries are marginal in terms of the commercial viability. With the increase of developing and operating costs, there is a growing need to reduce the cost of drilling and other allied operations. The hydraulic program for the deep wells constitutes a significant portion of the well planning. Challenges associated with extreme depth, pressures and temperatures translate to additional problems to the well design. As the wells are drilled deeper and deeper, accurate prediction of the wellbore pressures are increasingly important. Also, more wells are drilled in rotary steerable mode. Alternating between the sliding and rotary modes results in hole spiraling and wellbore oscillation becomes more pronounced due to frequent slide drilling. The estimation of pressures during drilling are indispensable for making appropriate well completion decisions. The prediction of wellbore pressures and downhole equivalent circulating density are of critical importance in wells where the pressure must be maintained within narrow limits of pore and fracture pressures.

This paper presents a study on how to adapt to the new wellbore hole spiraling effects encountered in ultra deep wells. This paper examines some of these effects, while asserting that it is necessary to integrate this new approach, so that more accurate solutions can be predicted as a result. This new hydraulic design encapsulating hole spiraling effects provides a simple, practical way to view the severity of the wellbore oscillation.
A Novel Approach to Liner Floatation Extends the Standard Well Reach in a North Sea Field Development
Authors: Wang Zhihua , Musaeus Nils N. , Frøland Stig
Published: December 2007

This paper presents a case study for floating a 9-5/8" liner using a novel approach and its implication to the on-going Ringhorne platform development program. The paper describes the planning, testing and execution of the liner floatation job performed in a record-setting Ringhorne well. A standard and field proven 9-5/8" liner hanger system was modified, tested, and used as the mud-over-air isolation device. This system was used to run a 4560 m long 9-5/8" liner to a depth of 5961 m with 6-5/8" drill pipe as the landing string.
Evaluation of Cement Systems for Oil and Gas Well Zonal Isolation in a Full-Scale Annular Geometry
Authors: Boukhelifa L. , Moroni N. , James S. G. , Le Roy–Delage S. , Thiercelin M. J. , Lemaire G.
Published: December 2007

In a wellbore, loss of zonal isolation can be caused by the mechanical failure of the cement or by the generation of a microannulus. However, the behavior of the sealant is driven by the specific boundary conditions like the rock properties. Large-scale laboratory testing of the cement sheath in an annular geometry and in a confined situation was performed to simulate various well conditions and to evaluate the behavior of several sealants under simulated downhole stress conditions. The failure modes of the cement sheath were determined as a function of the cement mechanical properties, loading parameters, and boundary conditions. The results were used to validate an analytical model that predicts cement sheath failure.
Remediating Sustained Casing Pressure by Forming a Downhole Annular Seal with Low-Melt-Point Eutectic Metal
Authors: Carpenter Robert B. , Gonzalez Manuel E. , Granberry Verland , Becker Thomas E.
Published: December 2007

Proposal

Described are proof-of-concept developments to form a seal for mitigating sustained casing pressure caused by annular pressure buildup. Annular pressure can result from numerous sources, including tubing leaks, loss of isolation potential within the cement column because of poor mud displacement, free water-induced channels, stress fractures, and failure of the cement to cover all potential sources of annular pressure. In most cases, annular pressure is not observed at the wellhead until the well is placed on production, making it difficult to identify, access, or remediate the pressure source. A new and novel approach to remediation has been tested in which a low-melt-point alloy metal is dropped down the backside of the casing where annular pressure has been observed. The metal is allowed to accumulate at the top of cement or other physical barrier, melted with an induction-heating tool, and allowed to cool and solidify. This process forms an annular seal to stop fluid communication between the formation and wellhead.

This method was demonstrated within a full-scale, simulated well section. An electromagnetic induction tool provided sufficient localized heating to completely melt solder-type alloy metal placed between concentric casings. Subsequent pressure-testing verified that a complete melt, sufficient to provide an effective seal against fluid pressure, was achieved in both water- and synthetic-based drilling fluids. Shear-bond test results of various alloys were equal or superior to cement, and the solid-liquid phase transitions (set points) occurred at precise temperature levels. All metals tested contained bismuth because of its unique characteristic of expanding upon solidification to provide enhanced pressure-containment performance. Full-scale testing was conducted using 17-ft long concentric annular models constructed of 8-in. and 5-in. diameter steel pipes. Subsequent field-testing is currently being planned.
World's First Completion Set Inside Expandable Screen
Authors: Gilmer Mike , Emerson Brent
Published: December 2007

This paper will discuss the utilization and flexibility of expandable screens in open hole environments. It will provide a case history of a significant "World's First" where a completion was set inside expandable screen. The completion provided a single selective well, where one could selectively produce different zones in the reservoir. Expandable packers provided isolation in the open hole, while a conventional completion packer provided isolation inside the expandable pipe.
Breakthroughs using Solid Expandable Tubulars to Construct Extended Reach Wells
Authors: Demong Karl , Rivenbark Mark , Mason David
Published: December 2007

Many modern well construction techniques have been developed with an eye toward drilling deeper, longer, and more cost effective Extended Reach Drilling (ERD) wells. One notable technology that has contributed to this effort is solid expandable tubulars. This technology was developed specifically to allow additional casing strings to be run to cover up problem zones and facilitate drilling the well to the ERD target. Solid expanable tubulars also help to reduce the overall resources required to construct the well. Projections show that using them would significantly reduce the size or volume, as well as the cost of the rig, the drill string, the bits, the cement, and, of course, the casing, resulting in lower overall costs. This result has been born out in practice and will culminate in the single-diameter well described elsewhere.1

The effects on ERD wells will be substantial, but there are important ‘side effects’ that can have a profound cumulative effect. The torque and drag on an ERD well is usually the limiting factor in the actual reach possible. These limits are mitigated by drilling fluid properties and the use of rotary steerable drilling tools among other technologies. Torque and drag are primarily influenced by geometric conditions like dogleg severity (DLS) and casing open hole size vs. drill string size, surface effects (commonly grouped together and named the friction factor), and drill string dynamic conditions (such as axial and rotary motion that overcomes the friction). The use of solid expandables has two distinct effects that can be favorable for the drilling of ERD wells. An important effect is that more favorable drill string casing geometry is possible and can reduce the tendency for helical buckling or drill string lockup. Another important impact is the ability to use larger drilling tubulars.

This paper will examine data supporting the positive effect of solid expandable tubulars on drill string torque and drag. Data modeled for an ERD well shows the theoretical drilling limit improvement from these effects in real example wells. Extended reach drilling limitations have been pushed out significantly in recent times. Advances in mud systems, geomechanics, and the advent of rotary steerable systems have significantly improved the ability to reach further to access hydrocarbons. However, limitations, though receding, still exist. To counter them, new approaches are being developed that attack in various ways the traditional boundaries of extended reach drilling applications.
Pore Pressure/Fracture Gradient Prediction Challenges: The Successful Design and Implementation of a Remote Exploratory Well Plan
Authors: Hradecky David C. , Postler Daniel P.
Published: December 2007

The recent successful drilling of Devon Energy Ghana's Tarpon 1-1X Miocene test well is evidence that the application of current 3-D seismic technology, accurate modeling, and the proper expertise, can lead to accurate pore pressures and fracture gradient predictions without direct offset well information.

The well was drilled in 6,330 ft of water, making it the deepest water depth oil and gas exploratory well drilled offshore Ghana. The nearest wells from which data could be obtained for analyzing the lithology and stratigraphy of the Tarpon 1-1X were shallow-water, shallow-depth wells that penetrated older Cretaceous formations not targeted by the Tarpon well. For this reason, the data were less than reliable for comparative purposes.

Instead, seismic interval velocities extracted from the 2-D and 3-D seismic surveys were used to predict pore pressures and fracture gradients.
The Use of Vertical Interference Testing to Improve Reservoir Characterization
Authors: Kuchuk Fikri J. , Halford Frank , Hafez Hafez , Zeybek Murat
Published: December 2007

Stratified or layered carbonate reservoirs are common in the UAE and throughout the Middle East. For field development and reservoir management it is important to describe the layering in terms of the vertical and horizontal layer permeabilities and the vertical communication between layers. Vertical communication between layers affects the overall development plan, the economics and management of enhanced recovery projects. The number and placement of both injector and producer wells will require an accurate description of the layering.

In this paper, we discuss the use Interval Pressure Transient Testing (IPTT), which is also commonly called Vertical Interference Testing, and Vertical Pressure Profiling in a major oil field in UAE. The objective was to characterize the vertical and horizontal layer permeabilities and vertical communication through the main producing reservoir section.

In a newly drilled and uncompleted well, eight IPTT tests were conducted with a Formation Tester Dual Straddle Packer and two Probe Modules. The vertical pressure profile along the wellbore was also obtained for information about the geology and flow units as well as depletion.

The interval pressure test at each location was interpreted using an appropriate geological model with the packer and probe pressure and flow rate measurements. The interpretation procedure consisted of identification of the different flow regimes followed by history (type curve) matching for the estimation of vertical and horizontal permeabilities for each layer. The interpretation of two of the interval pressure transient tests is presented.
Low Cost Well Intervention Using Wireline to Evaluate and Repair Tubing Leak
Authors: Burkhead David , Ahmad Mubashir , McCabe Marc , Willems Jan
Published: December 2007

Introduction

Well X-1 had developed significant communication between the 4 ½ inch tubing and production casing. This was confirmed by well head pressure measurements and diagnostic testing. Slick line testing with a "pony tail" confirmed the presence of a hole in the tubing at approximately 10,854ft. Consideration was given to set a straddle packer across the leaking tubing section, but that would only be effective if the overall state of the tubing was acceptable. If not, a work over rig would be required to pull and replace the completion.

The extent of corrosion in the tubing was evaluated using a Microvertilog (VRTM) tubing inspection tool (Figure 1). Unlike a multi-finger caliper, the VRTM evaluates the inside and the outside of the tubing for defects. If the evaluation of the VRTM data would show that the corroded sections were sufficiently localized, a straddle packer run on wireline could be used to repair the well.

Tool Theory

The Microvertilog service utilizes magnetic flux leakage measurements to determine the location, extent and severity of corrosion and other metal loss defects in the tubing. A permanent magnet produces high levels of magnetic flux within the tubing or casing wall. Defects in the tubing cause flux disturbances or "leakage", that are detected by a circumferential array of inductive coil (FL) sensors. The flux leakage measured by each sensor is recorded at surface (or in memory) and displayed as FL1, FL2.......FL8 (Figure 2). The tools also have a circumferential set of discriminator sensors (DIS1, DIS2....DIS8). These sensors are aligned with the FL sensors and respond only to flux anomalies on the inside wall of the tubing. By combining this FL and DIS data it is possible not only to determine location and severity of a defect, but also to differentiate whether the defect is internal (Figure 3) or external (Figure 4). It is also possible to distinguish between a metal gain (centralizers, down hole hardware -Figure 5) and a metal loss (corrosion, milling defects - Figure 6).
The Prediction of Cloud Point Temperature: In Pure Paraffin Deposition
Authors: Sadeghazad Ayoub , Sobhi G. Ali
Published: December 2007

The main object of this paper is to evaluate and discuss the cloud point temperature dependence on the solution nature in the crude oil. A correlation was also developed to predict the cloud point temperature in paraffin precipitation.

The cloud point temperature is an important parameter to see weather there will be paraffin precipitation or not. So, we interested on the parameters that affect the cloud point temperature of pure paraffinic hydrocarbons. Therefore, besides literature survey, some experiments on paraffin precipitation and deposition have been performed and evaluated. We mean heavy paraffinic hydrocarbon components by the pure paraffins.

Based on our experimental observations, the most important parameters that affect the hydrocarbon cloud point temperature are the apparent molecular weights of solution and solute, and solute weight fraction. These are the basic parameters of our developed correlation. In other words, the correlation is based on the intensive properties of the solution components such as their molecular weights and melting point temperatures, and the extensive properties such as weight fractions.

Through the regression process different equations have been used and a complex nonlinear polynomial equation was selected to obtain a correlation which predicts the cloud point temperature with less than 1.8-percent error. This modeled correlation is very simple to use and less time consuming with respect to the other models.
Unconventional approach to resolving primary and secondary porosity in Gulf carbonates from conventional logs and borehole images
Authors: Akbar Mahmoud , Chakravorty Sandeep , Russell S. Duffy , Al Deeb Maged A. , Efnik Mohamed R. Saleh , Thower Roxy , Karakhanian Hagop , Mohamed Sayed Salman , Bushara Mohamed N.
Published: December 2007

Traditionally, downhole porosity measurements are made through nuclear/acoustic logs (both wireline and logging-while-drilling) and cores. In homogeneous carbonates, log porosity is generally a good substitute for core data. However, in heterogeneous carbonates with complex pore systems resulting from leaching/dissolution, cementation, and dolomitization, discrepancies exist between log- and core-derived porosity. Moreover, thin-bedded layers of high and low porosity, which are found to have a pronounced effect on reservoir production, are routinely unidentifiable on conventional logs because of their limited vertical resolution capabilities (2-3 feet).

An innovative methodology has been developed to generate a porosity log with a minimum vertical resolution of 0.2 inch that also takes into account the azimuthal heterogeneities of the carbonate reservoir exposed in a wellbore. To achieve the high-resolution porosity log and entire porosity spectrum around the well, borehole images are used as external constraints after calibration with log porosity and resistivity. This methodology has significant applications in carbonate reservoir characterization. First, the identification of thin intervals of very high (related to high permeability) and low (dense, stylolitic) porosity is possible. Second, vuggy and moldic porosity can be quantified, and third, carbonate facies and reservoir rock types can be characterized. Several case studies from the U.Cretaceous / L. Cretaceous reservoirs and Upper Thamama Reservoirs highlight the effectiveness of the methodology to characterize porosity heterogeneity. Known porosity variations from core and mercury injection data confirm the heterogeneity demonstrated on the high-resolution porosity log. Since most carbonate reservoirs exhibit considerable porosity heterogeneity, this methodology has significant potential application to improve reservoir characterization in many areas.
The Comparison of Non-Aqueous and Aqueous Scale Inhibitor Treatments: Experimental and Modeling Studies
Authors: Guan H. , Sorbie K. S. , Mackay E. J.
Published: December 2007

This paper describes results from a series of comparative core floods and static compatibility tests examining the differences in laboratory test procedure, scale inhibitor (SI) returns and modeling approaches for non-aqueous and aqueous scale inhibitor treatments. Two types of non-aqueous system, one ethylene glycol based and two oil soluble products each containing penta-phosphonate scale inhibitors, were investigated. Detailed compatibility and injectivity tests were carried out before core flooding and special consideration was required in the treatment process due to their hydrophobic property. To understand the scale inhibitor transport and retention mechanisms for these non-aqueous products, comparisons were made with the relevant aqueous applications in terms of scale inhibitor return performance, flow back permeability, possible formation damage and wettability conditions which might account for any post-treatment changes. In addition, possible approaches to mathematically modeling these core floods were studied. This paper will focus on the application of a partitioning model in a standard reservoir simulator. An alternative two-phase mathematical model for such systems, which includes both inter-phase partitioning and adsorption has been described in detail in another recent publication.1

All core floods were performed using outcrop Clashach sandstone material rather than reservoir cores, and hence the advantages of deploying non-aqueous treatments over the conventional aqueous treatments would not be significant. However, the experimental and modeling results help to capture the features of these non-aqueous systems in an understandable way. Results confirmed the existence of complicated phase behavior during the core floods using two oil soluble products. Examination of the core after flooding using an environmental scanning electron microscope (ESEM) indicated decreased water wetness following the two oil soluble scale inhibitor treatments compared with the aqueous treatment. Numerical modeling results show that the behaviour of this system is most consistent with the assumption that the SI in the non-aqueous system is only slightly soluble in the oil phase during the oil post flush.
Accelerated Mechanism of Scale Deposition in UW Production Operation
Authors: Millan Juan Carlos , Dubey Sheila , Koot Wouter
Published: December 2007

An extensive study has been executed to understand the mechanism of calcite scale deposition occurring in the main heat exchanger at the MPP (main production platform) facilities at SVSA. The deposit necessitated a change out of the internals of the heat exchanger, which caused production deferment and capital expenditures.

The conclusion of this investigation was that the mechanism for accelerated calcite scale build-up in the HX heat exchanger is driven by the considerably high skin temperature (above 120 °C at normal heating conditions) in a high pH environment. This latter is caused by the triazine, which is part of the H2S scavenger package (used to remove H2S from some of the sour gas production), and by-products originating from the reaction of triazine (an amine) with H2S. The CaCO3 scaling tendencies and indices as calculated by scaling software (ScaleChem, StreamAnalyzer) predict the adverse impact of the high temperature and alkalinity conditions encountered in the heat exchanger.

Several technical options to mitigate the effects of the scavenger were considered from an economic and operational perspective. The most effective of the options was the injection of an appropriate scale inhibitor at a suitable dosage upstream of the heat exchanger.
Assessment of Scaling Tendency of Campos Basin Fields Based on the Characterization of Formation Waters
Authors: Bezerra Maria C.M. , Rosario Francisca F. , Rocha Anderson A. , Leonel Franca Fundação Padre , Sombra Cristiano L.
Published: December 2007

Campos basin reservoirs are responsible for an average oil production of 1.2 million bpd (83.5 % of Brazil's total production) with a forecast of 1.6 million bopd by the end of 2005.

cThis production comes from forty-one oilfields located between 50 to 140 km off the Brazilian coast (under water depths from 80 to 2.400 m) displaying a variety of reservoirs including Neocomian fractured basalts, Barremian coquinas, Early Albian calcarenites and late Albian to early Miocene siliciclastic turbidites (most frequently)(1).

Scaling risk for new fields is usually assessed in time as an input in the development phase of field projects. In order to guarantee a reliable formation water sample, from appraisal or development wells, a protocol was created based on data from twenty-six bottom-hole samplings. Correlations between produced fluid volume, porosity and permeability of the reservoir and the contamination degree were determined and used to define the minimum time of pumping necessary to have non contaminated samples.

This paper outlines the scaling tendency of the main fields from Campos Basin, based on the chemical composition of the waters and its association with the reservoir types. Scale risk of the fields is an important tool to be considered on the development phase project to support the decisions related to the appropriate technology to be adopted.
Experience with Pre-Emptive Squeeze Treatments on BP Magnus with Aqueous Based Scale Inhibitors
Authors: Strachan C. J. , Heath S. M. , White K. , Williams G. , Strong A. , Bell K.
Published: December 2007

Barium sulphate scale is a major problem in the BP Magnus field, even at low water cuts (<1%). In the late 1990’s BP Magnus adopted a policy of performing pre-emptive scale squeeze treatments on newly completed wells to prevent scale deposition and maintain well productivity on water breakthrough.

Squeezing dry and low water cut wells with aqueous inhibitor treatments can cause formation damage and result in changes in near well bore wettability. At this time, core flood studies carried out with conventional aqueous based inhibitor treatments indicated that it was possible to safely deploy these treatments in BP Magnus core material. A successful field trial was performed in 1998 since when it has been standard practice on the BP Magnus asset to pre-emptively treat dry and low water cut wells with aqueous inhibitor treatment packages.

Over the last few years a range of non-aqueous treatments technologies have been developed including oil miscible, emulsion and truly oil soluble scale inhibitors. Laboratory core flood studies have therefore been performed with these technologies, as they were developed to compare and contrast their performance to the use of aqueous based scale inhibitors.

This paper will detail a comparison of the core flood studies with both non-aqueous and aqueous based inhibitor treatments and will highlight that it is not always necessary to perform non-aqueous based treatments in dry and low water cut wells. An economic comparison of non-aqueous and aqueous based inhibitor treatments will be presented and, in addition, the paper will present the field experience gained to date with aqueous pre-emptive squeeze treatments in the BP Magnus field and outline the future scale management strategy for treating multi-lateral wells.