bluuebunny/crossref_metadata_2025 huggingface dataset:
Designing Invert Drilling Fluids to Yield Environmentally Friendly Drilled Cuttings
Authors: Growcock F. B. , Curtis G. W. , Hoxha B. , Brooks W. S. , Candler J. E.
Published: December 2007

An invert emulsion drilling fluid has been developed that possesses the drilling properties of conventional invert muds, yet can be discharged onto land as a soil enhancer. The individual components of this Soil-Enhancing Synthetic Based Mud (SE-SBM) -- base fluid, internal polar phase, emulsion stabilizers, wetting agents, fluid-loss-control agents and weighting material -- also possess these attractive features.

One version of the SE-SBM produces mud-laden cuttings that can be land-farmed directly without pretreatment. Where discharges are severely restricted with respect to salt, oil and/or grease content, another version of the SE-SBM is particularly well suited for pretreatment of the cuttings in a bioreactor or other rapid biotreatment technique.
Avoiding Catastrophes in Dynamic Positioning; Integrating Key Parameters Using a Systems Approach
Authors: Weingarth Lew
Published: December 2007

Recent newbuild and major upgrade deep water Dynamically Positioned (DP) rigs have been plagued by station-keeping difficulties. Many of these problems have been attributed to the DP system, the power management system, or the DP operators’ capabilities. Maximum efficiency and minimum non-productive (down) time for DP rigs can best be achieved by using an approach that considers all of these factors simultaneously – a SYSTEMS approach.

DP operation successes and failures will be illustrated using case studies from five drilling rigs with which the author has personal experience. Each of these cases will demonstrate the inter-dependence of critical equipment and systems that allow a rig to maintain position.

Additionally, the paper will describe latent problems identified, as well as describe why a systems approach would have avoided them. Primary emphasis will be on the symbiotic relationship between the DP and power plant management control systems, as well as the resident anti-blackout software in both. Cases will illustrate:Who's right, DP or power management?The DP rabbit and power plant turtle.How lack of DP operator knowledge can defeat even the smartest software.When does too much redundancy reduce reliability?What happens when one computer doesn't notice the other one died, or why is it critical that BOTH systems be designed as parts of a whole?

Finally, a brief analysis will offer how to best implement the systems approach on future projects, from both the owner and operator viewpoints. The analysis will cover how the systems approach impacts the following:Making certain that lessons from prior catastrophes are incorporated in the current projectUtilizing the relative strengths of in-house and third party personnelUnderstanding effective DP operator trainingEnhancing troubleshooting and downtime avoidance
Design for Semisubmersible Deepwater Development Drilling Unit Conversions is Achieved by Careful Listening
Authors: Quintero Alan
Published: December 2007

Atwood Oceanics, Inc. is upgrading two of its third generation semisubmersible units to operate conventionally in up to 5,000’ of water. In preparation for these upgrades we asked ourselves: "How do we decide what items to upgrade, and to what extent are these upgrades value added?" This paper will present the process Atwood Oceanics took to determine what upgrades we would undertake, and will summarize our final definition of a "fit for purpose, 5,000’ semisubmersible" based on the research.

In 1999/2000, Atwood Oceanics, Inc. was in the process of planning an upgrade to the Atwood Eagle from it's existing 2,000’/3,300’ water depth rating to 5,000’ of water. To prepare the upgrade scope Atwood Oceanics, Inc. researched published specifications of competing units. The data was split into two classes of rigs: 3,500’ to 4,000’ of water depth rating, and 4,500’ to 5,500’ of water depth rating. Items reviewed included general particulars, mooring systems, lifting, drilling equipment and mud system. From the research Atwood Oceanics conducted, we developed specifications for a "mid spec" rig in each of these categories.

In addition, Atwood decided to go to its clients to get input to what the industry believes a "fit for purpose, 5,000’ of water depth drilling unit" is. We met in small groups with some of our clients, and sent a client survey to 14 contacts in nine companies.

This paper will include the results of the client survey, the "mid spec" rig specifications developed, how these specifications were converted to an actual upgrade scope, and a discussion of why certain decisions were made. This information should give the industry a good snapshot of value-adding features of drilling units, and may serve as a first-pass tool for rig selection.
Cost-Effective Subsea Drilling Operation on the Smallest Norwegian Field Development
Authors: Blikra H. , Andersen R. , Hoset H. , Vestvik J. , Berg H.
Published: December 2007

Drilling and completing 4 horizontal and one vertical injection well during the months from October 2000 to May 2001 cost-effectively developed the Glitne subsea field in the Norwegian Continental Shelf. The operation was completed six weeks ahead of budget time and included an extended drilling programme of additional 5000 m compared to the development plan.

This paper will focus mainly on the drilling operation and why it succeeded. It will also include a brief description of the whole field development solution. As time is the main cost driver on a subsea operation, beating the time schedule was the primary goal for this operation. The drilling programme focused on a well planned and effective batch drilling operation for all hole sections, and the extended use of cost-effective rotary steerable assemblies.
Real-Time Specific Energy Monitoring Reveals Drilling Inefficiency and Enhances the Understanding of When to Pull Worn PDC Bits
Authors: Waughman Robert J. , Kenner John V. , Moore Ross A.
Published: December 2007

Optimizing when to replace worn bits can yield substantial cost savings, especially in the high cost deep water offshore drilling fields, however, recognizing when a bit is "dull" and past its true economic life can be difficult. All too often, speculation and the hope that the bit will "break through" into something more drillable has remained the driving force for determining whether to change a bit or leave it in the hole. This decision making process is extremely inefficient and does not further the philosophy on continuous improvement.

The concept developed to dramatically improve this inefficient decision process involved measuring the mechanical energy input at the drill rig floor; calculating the drilling specific energy; checking current formation type via real-time downhole gamma ray readings; comparing the specific energy with the benchmark new bit specific energy and then using these values to assess the bit's "dull" state. This method has been proven to work in synthetic based mud systems where balling does not mask bit dull condition. Since both balled-new bits and dull bits exhibit similar levels of inefficiency, it was imperative the operator proved this process worked in water-based drilling fluids that had replaced earlier synthetic muds. Synthetic muds were replaced by the water-based fluids due to environmental concerns, cost, and improved performance in WBM. Recently, the operator established that this process worked in water based mud systems that are treated with anti-balling chemicals. The case studies where this methodology was developed will be presented and discussed.
An Innovative Approach to Stuckpipe Reduction in the Niger Delta
Authors: Magaji M. A. , Amoo Olufunso A. , Owoeye Oladele O.
Published: December 2007

Stuck pipe used to be the major problem resulting in 80% of lost time during drilling operation in Shell petroleum development Company, Nigeria, the major operator in the Niger Delta area. A survey on borehole stability in the Eastern SPDC operations between 1996-1999 showed that eight (8) string months was lost to hole instability problems. During the period, forty (40) stuck pipe incidents were recorded in 70% of the wells accounting for over 80% of the lost time. The alarming rate of reoccurrence of this industry problem made it necessary for management to seek for solution within. Subsequently a Stuck Pipe Risk Factor (SPRF) prediction Tool was developed based on prevailing occurrence and existing data. The tool is being used to predict the inherent risk of getting stuck in well planning and design stages. In addition to that, it is used for change control during drilling, especially when lithological, formation pressure and rock mechanical properties changes are encountered during the execution phase of the well.

This paper reviewed the implementation strategy of the SPRF tool in the well engineering Operation of SPDC-Nigeria, both at conceptual and execution stages. The review showed that as a result of strict implementation of SPRF in all stages of well Delivery processes, major stuck pipe incidence dropped to 7 in the year 2000 when a total footage 241,013ft was made compared to 27 incidence in 1999, when 234,814ft was made. This represent 75% drops in stuck pipe incidence in year 2000. Similarly a 58% reduction in Non Productive Time (NPT) was recorded in year 2000 compared to 1999; resulting in 45% reduction in money lost

In conclusion, SPRF Tool have come to be accepted in SPDC as a reliable, fast and accurate way of simulating well design with ultimate aim of eliminating potentials for stuck pipe problems. It is also extensively used at the well site for operational monitoring where significant lithological, formation pressure and rock mechanical properties changes have been encountered.

It has also earned Shell Nigeria a ‘Center of Excellence’ award by the Shell Group Global Hole Stability (GHOST) Team.
Marlin Failure Analysis and Redesign; Part 1, Description of Failure
Authors: Bradford D. W. , Fritchie D. G. , Gibson D. H. , Gosch S. W. , Pattillo P. D. , Sharp J. W. , Taylor C. E.
Published: December 2007

The Marlin Field is located in the Gulf of Mexico, Viosca Knoll Blocks 871/915, and was originally intended to be produced from a TLP via five dry tree penetrations. First production from the A-2 well began in November, 1999. Shortly thereafter a minor, but persistent tubing leak occurred. Between November 7 and November 20, Well A-2 was alternately flowing and shut-in, depending on shakedown of the surface equipment and availability of the pipeline. On November 20, the casing pressure jumped to shut-in tubing pressure, signifying a major tubing failure.

This first of three related papers describes the actions of an incident investigation team formed to evaluate the failure of Well A-2. Possible failure modes investigated by the team include:

Helical buckling of the production tubing, with or without the combined loss of a tubing centralizer; Crushing of the tubing by ratcheting displacement from a failed centralizer; Lateral deflection of the subsea wellhead; Collapse of the production (and/or intermediate) casing onto the tubing due to one or a combination of: Hydrate formation outside the intermediate casing due to gas migration from a shallow hydrocarbon zone, with subsequent dissolution during initial production; Non-uniform loading of the production casing due to the geometry of the sub-mudline pack-off tubing hanger; Leak of the production casing connection; Annular fluid expansion; Formation of a heat pipe in the production tubing by production casing / riser annulus; Casing wear on the intermediate casing; Excessive initial pressure resulting from setting the casing hanger seal assembly in the subsea wellhead; Inadequate performance of the tubing or casing, either due to an incorrectly run or inadequately manufactured joint.

The current installment will, by deduction from both analysis and the physical evidence, narrow the field of candidate failure modes to a small subset. The application of these results and analytical techniques as incorporated into the re-design of the subsequent completions is to be addressed in the second paper of the series1. The final paper describes the implementation of the redesign as an insulated tubing completion2.
Marlin Failure Analysis and Redesign; Part 3, VIT Completion with Real-Time Monitoring
Authors: Gosch S. W. , Horne D. J. , Pattillo P. D. , Sharp J. W. , Shah P. C.
Published: December 2007

Following the failure of the initial well in the Marlin field1 the preferred solution for completing the remaining wells was to control wellbore temperature via vacuum insulated tubing (VIT)2. Implementation of VIT required a number of computational and experimental innovations, including:

Provision for insulating the tubing couplings, the source of up to 90% of VIT heat loss; Detailed flow loop temperature profiles using both axial probes and radial probes traversing the annulus outside the VIT. These profiles supplemented the conventional values of overall heat transfer coefficient and thermal conductivity obtained from the flow loop measurements; VIT performance, as measured experimentally, must exceed both thermal and mechanical design bases.

As well survival depends on proper VIT performance, a distributed temperature monitoring system was developed and evaluated during full scale testing. On the Marlin TLP, fiber optic is run in each well along the length of the VIT to continuously monitor the production annulus temperature profile. A software system was also developed to take binary fiber data and feed an integrated thermal simulator-casing design software package that calculates safety factors for the B and C annuli. These real time safety factors interface with the platform alarm system and are continually monitored by operators. If a low safety factor is calculated, a well will be shut-in. In addition to feeding the platform alarm system, the software provides data to a web based plotting program. If a single joint of VIT loses its insulating properties, this specific joint can be identified and appropriate action taken. The monitoring system has also proved to be a valuable quality assurance measure for special annular gels used to minimize conduction and natural convection in the production annulus.

This paper focuses on the value of the combined VIT and fiber/software monitoring system as a means of both controlling and observing well thermal behavior. Typical temperature vs. depth curves are used to illustrate the detailed information retrieved.
Successfully Replacing Oil-Based Drilling Fluids with Water-Based Drilling Fluids: Case Study Demonstrates Value of Extensive Planning and Execution in Extended-Reach Well
Authors: Stawaisz R. , Taylor S. , Hemphill T. , Tare U. , Morton K. , Valentine T.
Published: December 2007

An extended-reach [ERD] well was planned and successfully drilled in Block 16/26 of the U.K. Central North Sea with water-based drilling fluid in an area where wells have historically been drilled with mineral oil-based and ester-based drilling fluids. With increasingly stringent environmental regulations, the current utilization of mineral oil-based fluids is dependent upon shipping all cuttings back to shore for processing and subsequent disposal, resulting in high supplemental costs. Additionally, potential adverse weather conditions could temporarily preventing the transfer of cuttings from the platform to a supply vessel, thereby curtailing the drilling operations and further increasing drilling costs. The operator realized that significant savings to the current overall well costs could be realized if a water-based drilling fluid system were successfully used to drill the large-diameter hole interval that produced the highest volumes of cuttings.
Expandable Sand Screen: Three New World Records in the Brigantine Field
Authors: Weekse Alex , Steve Grant , Urselmann Rob
Published: December 2007

Between October 2000 and March 2001, Shell Expro, operating in the UK sector of the North Sea on behalf of Shell UK Limited and ExxonMobil UK Limited set three new world records in the application of expandable tubular technology, in 6" horizontal hole. Firstly, deployment and expansion of 4000 ft of 4" Expandable Sand Screens [ESS] in Brigantine B; surpassing the previous record tenfold. Secondly, deployment of 7000 ft of 4" ESS in Brigantine A and fully expanding 4920 ft of this screen. Thirdly, using the modified Compliant Rotary Expansion System [CRES] for full primary expansion of 60 ft of the 2150 ft ESS as Proof of Concept deployed in Brigantine C.

Brigantine is a small offshore gas field located some 100 miles northeast of the Bacton Gas Terminal in the UK Southern North Sea. The field contains three small hydrocarbon-bearing blocks, deemed individually uneconomical since their discovery in 1986. However, Deliver the Limit [DtL] concept, teamwork and application of three new technologies improved the economics of these accumulations and hence another success story for Shell Expro.

The three new technologies are listed below: The Brigantine Wells were drilled from two minimum facility Trident Platforms, which had won international recognition for their revolutionary design.Geo-steering Technology was chosen to drill the long 6" horizontal sections to maximize reservoir connectivity and overcome the risk of compartmentalisation within the structures.An integrated sand study carried out confirmed the need for downhole sand exclusion. The selected option was the Expandable Sand Screen. This novel approach, developed by Shell Technology with Weatherford Completion Systems (WCS) having a licence, was preferred to conventional methods, such as ‘Gravelpack’, due primarily to the larger bore it provides to maximise deliverability and the high potential to eliminate annular flow when fully expanded against the wellbore. However, ESS Technology was in its infancy and classified internally as ‘new unproven technology’.

The three wells were completed 32 days ahead of plan, achieved initial production of between 23% and 40% above expectation with total ESS added value of £13.5 million.

The following paper documents the decision to choose ESS as the preferred Sand Exclusion Technology, and the ESS delivery process from ‘unproven technology’ to deployment and expansion in the Brigantine Wells.
Wedge Thread Tool Joints: Applications and Economics
Authors: Reynolds Harris A. , Greenip John F.
Published: December 2007

Series 500™ Wedge Thread™ (WT) tool joint connections were developed in 1993 for high-torque extended-reach drilling applications in the North Sea.

These non-shouldered connections offer extremely high torque limits and a small OD/ID profile for improved drilling hydraulics. The combination of features on WT tool joint connections has enabled a series of ground-breaking applications in extended reach and slim profile drilling around the world.

Recent analysis of more than 4 years worth of operational data on the Wedge Thread tool joint connection has yielded the unanticipated result that WT tool joint connections have lower average operating costs than API Numbered Connections (NC). In many cases, the marginal investment in a WT drill string has a payback of less than 2 years, independent of the special technical features of the connection such as higher torque and better hydraulics.

This paper describes the special drilling applications enabled by Wedge Thread tool joints, including considerations of drilling hydraulics, fishing, pipe running and handling, inspection and repair, and especially the concept of using one WT string to substitute for two conventional NC drilling strings.

A methodology is presented for evaluating the economics of using WT tool joints connections in everyday drilling, in lieu of API Numbered Connections.
Effect Of Hydrate Inhibitors On Oilfield Scale Formation And Inhibition
Authors: Kan Amy T. , Fu Gongmin , Watson Malene A. , Tomson Mason B.
Published: December 2007

The effect of hydrate inhibitors on oilfield scale formation has been studied. A self-consistent activity model is presented to model the effect of methanol on carbonate equilibrium, calcite, barite, gypsum, celestite, and halite solubility in a gas/methanol/water/salt solution. The model uses Pitzer theory to model the effect of salt and Born equation to model the effect of methanol. Excellent agreements between the model prediction versus both experimental and literature results are observed. The model has been incroporated into ScaleSoftPitzer®, a scale prediction software specifically written for the oil and gas industries. From ScaleSoftPitzer® predictions, scaling problems can be worsened with as little as 5% (by volume) of methanol in a typical oil and gas production system. Ethylene glycol has a much lesser impact on oilfield scale formation than methanol. The efficiency of common phosphonate inhibitors in the methanol and ethylene glycol containing brines will also be discussed.
Saturation Modeling in a Multilayered Carbonate Reservoir Using Log-Derived Saturation-Height Function
Authors: Kumar Rajesh , Cherukupalli P. K. , Lohar B. L. , Chandra Dinesh
Published: December 2007

The conventional and widely used way of distributing saturation arrays inreservoir simulation models is through porosity-weighted water saturationvalues. In this way, each grid cell has an assigned porosity and initial watersaturation. The porosity and water saturation are estimated with the help ofwell logs using established procedures. However, for producing reservoirs, logderived saturations may not represent initial saturations due to variousreasons like depletion due to production and effect of water injection etc. Oneof the ways to estimate the initial water saturation is by the use ofrelationship between depth and bulk volume of water (BVW). Such relationship, known as Saturation-Height function is used to estimate saturation values awayfrom the well locations and to calculate the hydrocarbons in placevolumetrically. This approach has been used in a multi layered carbonatereservoir of an Indian offshore field.

Layer-wise saturation height functions are developed by establishingrelationships between height above the free water level and bulk volume ofwater derived from the wells drilled in the initial phase of field development.The scatter in the BVW plot has been reduced by further classifying the datafor different porosity facies. These porosity intervals are treated as rocktypes for that layer. Since each layer has a particular range of porosity, different porosity based rock types are identified. Height above the free waterlevel versus water saturation plots are then generated for different rock typesusing the relationship developed for each geological layer.These equations wereused to assign initial water saturation in the reservoir simulation model.
Estimating Subsidence During Coalbed Methane Production
Authors: Fanchi J. R.
Published: December 2007

The purpose of this paper is to show how to estimate geomechanical parameters and subsidence during coalbed methane production using the petrophysical algorithm in an integrated flow model. The integrated flow model has been extended to model production of gas from coalbeds and estimate associated geomechanical properties. The model is applied to coals with desorption properties associated with Fruitland coal and Pocahontas coal.
Application of Decline Curve Analysis in Gas Reservoirs Using a Newly Developed Fitting Equation
Authors: Zelghi Ferhat , Djebbar Tiab , Mazighi Mohamed
Published: December 2007

Decline curve analysis for a gas field is generally difficult with the conventional type curve matching, especially in the early time period. For this reason a newly developed fitting equation is proposed as an alternative for gas field production data analysis. This equation combines both depletion and transient periods. The equation offers the following advantages: Fitting with the new equation is more precise than the conventional type curve matching to obtain decline constant, D, and decline exponent, β, and matching point.The real production data can be fitted directly by the equation without using smoothing techniques.The radial and pseudo-steady-state regions are determined directly from the fitting.For new-developed reservoirs, production data, which may be insufficient with the conventional type curve matching, can be interpreted with the new fitting equation.

In this paper, a case study is presented to illustrate the application of the new equation for decline curve analysis in a gas reservoir.
Specialized Cement Design and Placement Procedures Prove Successful for Mitigating Casing Vent Flows—Case Histories
Authors: Watson Theresa , Getzlaf Don , Griffith James E.
Published: December 2007

This paper documents recent field cases in which attempts were made to mitigate casing vent flows (CVF's) on producing and abandoned wells by incorporating permeability-blocking gels with specialized cement blends. CVF's are defined in this paper as sustained gas pressure on the annuli of producing and surface casings. The amount of gas flow rate can vary from a few bubbles to cubic meters per day. However, when the annuli are shut-in, the gas pressure can build to a significant amount. The procedures detailed in this paper are the result of lab studies and postjob reviews of failed remedial attempts. Specific attention is given to why squeeze-cementing procedures can fail to provide long-term seals against source-gas production from casing vents. In most cases, rework of the abandonment procedures cost the operators over $200,000 CAD.

The studies showed four possible causes of recurring CVF's: Development of thaumasite in the setting cementLeaking isolation toolsIncomplete long-term seal of source zonesIncorrect source detection or squeeze interval

Cement-source quality and bulk handling methods were also investigated, but showed no evidence of probable cause.

This paper explains the findings from laboratory studies and job reviews that lead to improved procedures. These improved solutions were conducted on 23 wells in the later part of 2001.
Innovative Water Shutoff Solutions Using Coiled Tubing Conveyed Inflatable Devices
Authors: Geddes Martin J. , Mackenzie Gordon R. J.
Published: December 2007

With water production continuing to increase from mature reservoirs and the need to enhance hydrocarbon recovery from these reservoirs economically using existing wellbores, the requirement for innovative thru-tubing zonal isolation solutions has never been greater. Due to the complexity of the completion design and reservoir in mature fields, the benefits of high-expansion plugging devices and coiled tubing conveyance for chemical placement have become increasingly important.

Thru-tubing inflatable technology has, for some time now, been providing high-expansion devices to pass through the existing completion and isolate in the liner or casing below. However, as reservoirs deplete and remedial work such as re-perforation is performed, the conditions in which these tools are required to perform are becoming ever more challenging. This paper will focus on two coiled tubing water shutoff interventions using thru-tubing inflatable technology in conjunction with cement or chemical placement. In these interventions, the wellbore conditions were considered particularly challenging – sub-hydrostatic bottomhole pressure, multiple perforated intervals and an existing zonal isolation device in the form of a straddle. These case histories will be examined in detail, with emphasis on the pre-job planning, equipment selection, operational procedures, lessons learnt and post job results.
An Advanced Environmental Management System for Alaska
Authors: Hermannes K. , Lawrie G. , Sealy I. , Thayer R.
Published: December 2007

Oil and gas development in Alaska takes place in some of the most environmentally sensitive operating areas in the world. Federal, state and local governments regulate oil field activities in Alaska. The planning and development of new projects can require permits from as many as 26 different agencies.

Meeting our company goal of "No harm to the environment" in this highly sensitive area required a unique solution. In response to developments in customer, industry and societal expectations for environmental performance in our industry in Alaska, we developed an advanced Environmental Management System (EMS). This paper describes the process of developing and maintaining that system.

Key features of our EMS development program included: formatting the EMS to have the look and feel of the corporate HSE management system for ease of implementation and user understanding; the use of established corporate HSE tools wherever possible; the use of external auditing for assurance, for system benchmarking and for compliance assurance; the development of tools using external best practices where required.

The EMS has been benchmarked against the International Environment Rating System (IERS), an internationally recognized Standard for environmental management. The EMS achieved a Level 3 rating in 2000, and a Level 6 rating in 2001 by independent verification company, Det Norsk Veritas. Level 4 is considered to be the equivalent of achieving ISO 14001 accreditation.

The EMS has been implemented in six operational groups located at five facilities in Alaska and has had an immediate impact on our environmental performance. A significant reduction in spill rates, improved waste minimization and proactive environmental risk reduction have all been delivered. Established performance indictors, such as spill rate, have shown improvements of over 80% during the first the Quarters of 2001. Furthermore, several new environmental performance indicators have been developed to accompany the EMS.
Proactive Surveillance and Phased Development Yields Promising Results from the Aurora Field 30-Years after Discovery
Authors: Young J. P. , Bakun F. E. , Paskvan F. K. , Westergaard E. H.
Published: December 2007

Although three 1969 exploration wells discovered hydrocarbons in the Aurora structure, development was not possible until a scope change to the V-200 exploration well demonstrated commerciality 30-years later. Commencing in June 2000, an aggressive 6-well horizontal and vertical development/appraisal program yielded over 1.75 million barrels of oil in the first year and provided a better understanding of a reservoir previously thought marginally commercial. Investment in reservoir description and proactive surveillance led to accurate decision-making, and with innovations, yielded significant return from a "marginal" field.
Horizontal and Vertical Permeability Determination in Clean and Shaly Reservoirs Using In-Situ Measurements
Authors: Manseur Saadi , Djebbar Tiab , Berkat Ali , Zhu Tao
Published: December 2007

Measurements of reservoir rock properties are a difficult task. These rock properties usually involve costly coring programs plus extensive laboratory efforts. An alternate method to estimate these rock properties is using well-logging methods, which represent significant technical as well as economic advantage.

The purpose of this study is to enhance reservoir description of clean and shaly formations in both vertical and horizontal directions using well-logging data. A new approch has been developed for estimating the J-function in clean/shaly heterogeneous reservoirs. This newly developed correlation has been applied to field data, resulting in good matching. Based on leverett J-function and the new proposed approach for estimating J-function, a new correlation for estimating absolute permeability in the transitions zones has been developed. An investigation of permeability, porosity, and irreducible water saturation relationships leads to develop other two correlations in terms of cementation exponent, m, and saturation exponent, n, for estimating absolute permeability in the irreducible water saturation zones from well-logging data.

The feasibility of evaluating permeability distribution of a heterogeneous formation utilizing geophysical well logs has also been investigated, Ben kahla field in Algeria has been selected as a study area. A methodology has been introduced for estimating permeability profile using core and geophysical well log data.

Several vertical permeability relationships were obtained as a function of horizontal permeability, hydraulic mean radius, grain size, and the amount and/or type of shale. A procedure for determining vertical permeability from well log data is presented. The field data shows that the permeability correlation for predicting vertical and horizontal permeability can be established for a specific reservoir by using core permeability and well log data.
Designing a New Plan for the Redevelopment of a Mature Oil Field by Using Various Technologies
Authors: Chedid R. , Colmenares F.
Published: December 2007

A mature area located in Western Venezuela is enclosed by three main fields, all of them in advanced state of depletion based on the way they have been exploited up to now since 1930. These heavy oil fields have a crude that ranges from 10-14 °API, a viscosity between 1000 and 25000 cp and cyclic steam is the way of stimulation as an standard process for all the new wells and the workovers. Cyclic Steam is becoming less efficient after three cycles application, the steam to oil ratio (<5), which is too low for these fields. Since before reaching this value it used to be around 30-40 for the first three cycles, which is considered a good value. Considering that the oil in place is more than 20 billions barrel of oil and only 23% has been recovered beside the latest static models show that several of the sand bodies has not been drained out as yet. A different strategy or a new plan for the redevelopment of the area is necessary in such a way that the exploitation of these fields could be extended for twenty or more years. This study shows that with good static and dinamic models a reassessment of the whole area can be done, by ways of dividing into regions the fields and applying different producing technologies, some of these technologies are thermal recovery methods as cyclic steam, steamflood, SAGD, electromagnetism and Combustion. All of this will increase the recovery factor up to 80%. The non drained sand bodies could be stimulated by applying cyclic steam in areas of the field with good thermal communication. These are candidates for steamflood and in the areas with clean sand bodies up to 40 ft. Thick, SAGD can be applied. Finally the very depleted reservoirs with low pressure and clean sands are the best for either dry o wet combustion.
Analytical Study of the Wafer Non-Darcy Flow Experiments
Authors: Li Dacun
Published: December 2007

Non-Darcy effect is significant for high velocity gas flow especially when gas approaches the wellbore region. A new semi-theoretical equation was proposed to estimate the non-Darcy coefficient and the equation was verified by comparing differential pressures from simulations with their counterparts from the experiments where nitrogen was injected at various flow rates and in several directions into a wafer-shaped Berea sandstone core sample.

In this paper, the geometry of the wafer and flow profiles were simplified and an analytical model was developed to provide a quick method to estimate the directional permeability and non-Darcy coefficient. Data from several directions were processed statistically to find the best correlation for the wafer.

The analytical study confirmed that the new semi-theoretical equation was effective to be used to estimate the non-Darcy coefficient. The correlation for the wafer developed from the analytical study was found to lie between the parallel-type model and serial-type model and be closer to the latter one. Combination of correlations from analytical and numerical studies led to a general correlation, which was found to be the best for Berea sandstone samples after performances of the correlations in the literature and from this paper were independently evaluated by using the results of non-Darcy flow experiments in the literature.
Cumulative Rock Strength as a Quantitative Means of Evaluating Drill Bit Selection and Emerging PCD Cutter Technology
Authors: Cordy L. , Rogers D. B. , Karsten D. , Davies R.
Published: December 2007

The use of cumulative rock strength as a means of evaluating Polycrystalline Diamond Compact (PDC) drill bit performance has been successfully applied to the Cooper Basin, Australia by Santos Ltd. This has permitted a more engineered approach to PDC drill bit selection with a measurable improvement in overall performance.

As this field application consists of vertical wells, drilled in close proximity with similar parameters and operating conditions, it is possible to gain a high level of comparative data with quantified variables reduced to bit / cutter type and formation.

By cumulating the compressive strengths drilled above a determined limit, it is possible to compare bit runs and quantifiably evaluate existing and emerging bit /cutter types and thereby engineer future selections.

Field results have shown an average increase of 61% in the >25,000 psi Cumulative Overburden Compressive Strength formations drilled by the first PDC in the study area.

The initial success rate for the first PDC to get through the entire hard Namur/Hutton formations was 1 in 19 (5.3%). Utilization of the Cumulative Formation Compressive Strength (CFCS) methodology for bit selection increased the success rate to 75% for the last 4 full runs in the study, resulting in a reduction in rig time and associated costs.
Consequent Incentivizing of Service Contracts and its Long-Term Impact on Drilling Performance
Authors: Spoerker H. F. , Ringhofer W.
Published: December 2007

OMV has been drilling for oil and gas in a roughly 5000-km2-area northeast of Vienna for more than fifty years. Since 1999, previously applied conventional type service contracts were gradually changed to performance-based incentive type contracts, which increased drilling performance up to 50% over a three-year period. The impact of generating "ownership" within the service company’s and contractor’s staff is reflected by both the increased quality of the wells drilled and the enhanced safety record of the rig(s). The paper describes the incentive scenarios developed for a mature operating are, the pitfalls and obstacles that had to be overcome in implementing new contractual concepts in a traditional operating environment and the increases in operating efficiency gained from the new culture.
Pipe Buckling at Surface In Underbalanced Drilling
Authors: Aasen Jan , Skaugen Erik
Published: December 2007

Underbalanced drilling (UBD) with jointed pipe has become routine in the UK sector of the southern North Sea and operators in the Norwegian sector are now introducing the same concept. Typically, the well is kept live during tripping and a rig-assist snubbing unit is employed to handle the drillpipe while pipe-light. Significant surface compressive loading is exerted on the pipe during the snubbing phase. The focus of this paper is two-fold. First we consider buckling of the drillpipe in the snubbing jack and on the drill floor when a static compressive load is applied. Thereafter, we analyze the behavior of ejected tubulars during well entry and exit under live well conditions.
Buckling Models Revisited
Authors: Aasen Jan A. , Aadnøy Bernt S.
Published: December 2007

The complexity of petroleum wells has increased significantly during the past decade. Both inclination and horizontal departure are greater than before, leading to additional demands on well operations. Buckling of drillpipe and completion string is seen as a critical parameter. In this paper we review available buckling models and show applicable theory for practical well operations.
Mathematical Modeling of Gas Kicks in Deep Water Scenario
Authors: Nunes J. O. L. , Bannwart A. C. , Ribeiro P. R.
Published: December 2007

Well control has always been a very important issue in the oil and gas exploitation business, since it involves money savings, people safety and environment threatening. The advancement of the exploration frontiers from onshore to offshore fields, particularly, deep and ultra-deep waters, has increased even more the relevance of kick control and blowout prevention during drilling operations. Widely used drilling practices have been optimized and re-evaluated, so have new technologies been developed to handle specific issues related to deepwater drilling operations, such as reliable and efficient well control practices. This effort has great importance to some countries like Brazil, which have most part of their oil and gas production (close to 75%) concentrated on offshore wells, about 70% of those reserves are located in deep waters. Regarding such scenario, this article presents a comprehensive and discussed literature review about well control in deep and ultra-deep waters, covering the evolution of the analytical and numerical kick models. A mathematical model has been developed to predict the pressure behavior inside the annulus during a gas-kick circulation out of the well in deep water scenarios. Considerations regarding the effects of wellbore geometry, frictional pressure losses, influx expansion, and two-phase flow models have been implemented in the present model. The analysis of the effect of some important parameters in well control in the surface pressure, such as the pit gain, water depth, mud density and pump flow rate are presented.
Modeling Coupled Fracture-Matrix Fluid Flow in Geomechanically Simulated Fracture Networks
Authors: Philip Zeno G. , Jennings James W. , Olson Jon E. , Holder Jon
Published: December 2007

In conventional reservoir simulations, grid block permeabilities are frequently assigned values larger than those observed in core measurements to obtain reasonable history matches. Even then, accuracy with regard to some aspects of the performance such as water or gas cuts, breakthrough times, and sweep efficiencies may be inadequate. In some cases this could be due to the presence of substantial flow through natural fractures unaccounted for in the simulation. In this paper we present a numerical investigation into the effects of coupled fracture-matrix fluid flow on equivalent permeability.

A fracture-mechanics-based crack growth simulator, rather than a purely stochastic method, was used to generate fracture networks with realistic clustering, spacing and fracture lengths dependent on the Young's modulus, the subcritical crack index, the bed thickness, and tectonic strain. Coupled fracture-matrix fluid flow simulations of the resulting fracture patterns were performed using a finite-difference simulator to obtain equivalent permeabilities that can be used in a coarser scale flow simulation. Fractures were represented in finite-difference simulators both explicitly as grid cells and implicitly using nonneighbor connections between grid cells.

The results indicate that even though fracture permeability is highly sensitive to fracture aperture, the computed equivalent permeabilities are more sensitive to fracture patterns and connectivity. The effects of diagenetic cements completely filling smaller aperture fractures and partially filling larger aperture fractures were also studied.
Wet Gas Metering Using Dissimilar Flow Sensors: Theory and Field Trial Results
Authors: Agar Jo , Farchy David
Published: December 2007

This paper addresses a new approach to wet gas flow measurement. The Wet Gas Meter (WGM) combines dissimilar flow sensors to measure the flow rates of gas and liquid in gas well production. The WGM utilizes a vortex flow meter for volumetric measurement and dual venturis with different throat sizes for liquid/gas determination.
Innovative Design Method for Deepwater Surface Casings
Authors: Jeanjean Philippe
Published: December 2007

This paper presents a method to calculate the load bearing capacity of surface casings. The method clearly describes how to calculate the immediate capacity of the conductor and how to estimate the soil set-up with time. The recommended equations for set-up calculations are based on the results of three proof-load tests performed on partially set-up conductors. The paper also lists a series of key parameters that need to be controlled for a successful jetting operation. The overall method has been calibrated against 20 successful installation records.
Pore Pressure Prediction for the Cocuite Field, Veracruz Basin
Authors: Sayers Colin M. , Hooyman Patrick J. , Smirnov Nikolay , Fiume Giuseppe , Prince Antonio , de Leon Mojarro Jose C. , Romero Martin Terrazas , Gonzalez Oscar Marquez
Published: December 2007

Seismic velocities from a three-dimensional (3D) seismic survey over the Cocuite field in the Veracruz basin, Mexico, were used to predict pore pressure in order to optimize drilling operations in this area. The accuracy of the seismic velocities was assessed using a comparison with interval velocities calculated by upscaling sonic logs and by inverting time/depth pairs from check shots measured in wells in this area. To calibrate the velocity to pore pressure transform, available pressure tests and drilling mud weights were used to estimate formation pore pressure. This technique results in 3D models that are less uncertain and of higher density than conventional techniques, and that improve drilling safety and economics in overpressured areas.
Analysis of Black Oil PVT Reports Revisited
Authors: McCain William D.
Published: December 2007

Combinations of data from two laboratory procedures, differential liberation and separator test, are used to determine values of oil formation volume factors and solution gas-oil ratios for pressures below the bubblepoint pressure of the reservoir oil. The equation commonly used to calculate the solution gas -oil ratio is incorrect: the correct equation is derived. The equation used to calculate the oil formation volume factors is correct; however, a derivation illustrating the underlying assumptions has not been published. This derivation is also examined.
Ageing Facilities Present a Potential Environmental Threat
Authors: Sparks Ronald L. , Holliday George H.
Published: December 2007

Ageing Exploration and Production (E&P) facilities offer either a potential environmental threat or change. These potentials exist, if the property is retained or sold. This paper discusses the potential and sometimes real problems and/or benefits associated with holding or divesting of ageing producing properties. We have observed a number of old producing properties – some being retained, some being transferred from major producers to independent operators and more importantly, some being transferred from independent producers to minor operators. In either case, the original operator needs to evaluate the economics of elevating and maintaining the property to regulatory requirements prior to transfer. There is a real possibility the original owner must monitor the future operations of the divested lease to avoid future liability.

This paper provides insight into what circumstances place operators in jeopardy and how to evaluate the associated regulatory problems. Most papers discuss regulations from the programmatic aspect rather than a how-to-do aspect.

We concluded any potential buyer of an ageing producing property must either conduct or receive an environmental assessment of the potential for environmental problems. More importantly, the divesting operator must have confidence the purchaser will not devastate the lease or operate in an unsafe manner, leaving the remediation or liability to the previous or original owner. This is particularly true of the transfer from an independent operator to another independent operator. Further, there is need for the E&P industry to encourage the various Trade Associations to solicit regulatory protection after divestiture. The findings presented in the paper are based on personal observations of the authors.