bluuebunny/crossref_metadata_2025 huggingface dataset:
Straight Down to Success: Performance Review of a Vertical Drilling System
Authors: Reich Matthias , Oesterberg Marcus , Montes Hermilo , Treviranus Joachim
Published: December 2007

Rotary closed-loop steering systems are well known in the oil and gas industry and have become the accepted standard for drilling complex 3-D well paths and extended reach wells. These system's continuous drillstring rotation eliminates static friction between the string and the borehole permitting longer horizontal displacements in the reservoir and improving hole cleaning by stirring up the solids in the mud. While a 3-D rotary steering system could also be used to drill the hole's vertical top section, a closer examination reveals that efficiently drilling the top hole section requires a completely different approach.

Static friction and solids settlement are not critical issues in vertical hole sections — permitting the design of a Vertical Drilling System engineered to run without string rotation in sliding mode. This approach protects the borehole walls from mechanical damage and leads to improved hole quality. To compensate for the lack of drill string rotation, the system design incorporates a latest generation power section which delivers almost double the torque of a conventional power section of the same length. Also, because a Vertical Drilling System's sensor package typically requires only inclination measurements and does not need azimuthal data, the system's electronic design is simplified.

Although there are basic differences between 3-D rotary steering systems and Vertical Drilling Systems, there are also features which can be shared between both technologies — simplifying the service provider's engineering, maintenance, manufacturing and logistic efforts1. Examples of shared components include a steerable stabilizer to keep the BHA exactly on the desired (vertical) wellpath, the downhole power supply, the internal closed-loop information system and bi-directional data transmission.

The Vertical Drilling System is designed to keep the top hole vertical without interaction from surface and without compromising critical drilling parameters (flow rate, WOB or bit speed) while maintaining high ROP along the entire section and avoiding time-consuming correction runs. The resulting improvement in hole quality and the precise wellpath allows the use of "lean casing profiles" 2, 3—reducing the amount of steel, cement, mud and cuttings. Vertical Drilling Systems are also beneficial in reducing the wellhead spacing at surface. All of these benefits result in significant cost savings to any operator.

The paper describes the features of a Vertical Drilling System, presents case histories from 8-1/2" to 26" hole sections from various areas around the globe and gives an overview about the fast emerging market of this technology.
Use of Downhole Permanent Pressure Gauge Data to Diagnose Production Problems in a North Sea Horizontal Well
Authors: Gringarten Alain C. , Schroeter Thomas von , Rolfsvaag Trond , Bruner John
Published: December 2007

Permanent downhole pressure gauges are increasingly being installed in new wells in the North Sea and in other new developments around the world. Their reliability has greatly improved and they now can operate for several years. They provide a record of everything that is happening to the well and, in the long term, they will replace production tests for well and reservoir monitoring. The main difference with production tests, however, is that rate variations are not controlled, which can make the interpretation difficult.

The paper illustrates how the availability of three years' worth of pressure data from a permanent downhole pressure gauge was key to understanding and explaining a tenfold loss of productivity in a North Sea horizontal gas well. Four million pressure measurements were processed and analyzed both in the conventional way, one flow period at a time, and by deconvolution, using increasing durations of pressure records from the start of production. Interpretation identified progressive changes in gas relative permeability followed by decreases in the well length, suggesting water invasion of the well zone. This points out to the need for continuous monitoring of the interpretation of permanent gauge data, which is possible by deconvolution, to identify changes in well-reservoir behavior as soon as they occur and thus avoid potentially irreversible productivity problems.
Directional Resonance: New Applications for MRIL
Authors: Prammer M. , Menger S. , Knizhnik S. , Goodman G. , Harris E. , Drack E.
Published: December 2007

The paper describes a new Nuclear Magnetic Resonance (NMR) sensor geometry suitable for wireline logging and for LWD. The current Magnetic Resonance Imaging Log (MRIL*) tool utilizes multiple volumes that are concentric with respect to the tool. The new sensor further breaks down these volumes into four azimuthally distinguishable quadrants. Although the potential applications in LWD are obvious, the first implementation was done on wireline. The new sensor enables MRIL operation in large (12-¼ in. and up) and potentially badly washed-out boreholes. This wireline tool is compatible with all applications and all processing software developed for the current MRIL-Prime.

The field test results demonstrate the actual performance of the new design in a large borehole. By comparison with a standard MRIL-Prime log, we assess the log response and repeatability of the directional sensor.
Wireline T1 Logging
Authors: Bonnie Ron J. M. , Akkurt Ridvan , Al-Waheed Hilal , Bradford Charles M. , Eyvazzdeh Ramsin Y. , Phillips E. Craig , Aadireddy Prabhakar , Negm Ehab
Published: December 2007

With the recent introduction of NMR Logging While Drilling tools and down-hole NMR Fluid Analyzers, the more fundamental T1 measurement has made its appearance in the oil patch. In both these applications, the preference of T1 over T2 has been its insensitivity to motion, since T1 measurements effectively eliminate the detrimental effects arising from tool motion or fluid flow.

Experience has shown that the acquisition and interpretation of T1 logs recorded in the less hostile wireline environment is quite straightforward, mainly due to the absence of tool motion, while yielding several benefits over T2 logs. T1 is a critical fluid NMR parameter and can play a prominent role in fluid typing applications. Also, T1 data sets are more compact and the acquisition is more efficient. Finally, T1 logging offers the potential of substantially increased logging speeds

This paper outlines the current T1 logging practice, and substantiates the advantages of T1 logging using real-life data. Examples included demonstrate the value added by wireline T1 measurements into the overall petrophysical understanding of in-situ reservoir fluids.
An Engineering Approach To Predicting Post-Treatment Well Performance Using Selective Chemical Water Shut-Off Techniques: An RPM Example
Authors: Kume Nicholas
Published: December 2007

The demand for effective selective chemical water control techniques is at an all time high, as old fields tend towards maturity and decline. This has become even greater, as the industry trend is toward horizontal and high angle well completions, where techniques to mitigate water production at breakthrough and subsequent to that, still remain elusive. Even when an effective solution is identified in laboratory tests, the absence of a reliable method to predict actual job posttreatment performance remains a major obstacle to the building of confidence in the field. In addition to the difficulty in establishing conviction of potential users, a poor ability to predict the results also limits the ability to recycle and build on the successes of these technologies, as well as to explain their failures and improve on job designs.

The aim of this paper is therefore to present an easy method for predicting the outcome of selective matrix water control chemical treatments - specifically with relative permeability modifiers (RPMs). This method applies reservoir fluid mechanics principles and uses tools already available in the oil industry's predictive inventory. It also links laboratory test results with field performance prediction. The method is more of a guide. Specific field circumstances may lead to modification of certain assumptions. The core reasoning should however apply to most circumstances where RPM technologies are properly applied. As an initial tool for use, this approach should help provide a first order of magnitude performance prediction, while further applications and results would be used to fine tune its predictability.

This paper also presents an easy-to-follow procedure to assist with the understanding of this RPM-treatment prediction technique.
Predictive Pore-Scale Network Modeling
Authors: Valvatne Per H. , Blunt Martin J.
Published: December 2007

We show how to predict flow properties for a variety of rocks using pore-scale modeling with geologically realistic networks. Starting with a network representation of Berea sandstone the pore-size distribution is adjusted to match mercury injection capillary pressure for different rock types, keeping the rank order of pore sizes and the network topology fixed. Then predictions of single and multiphase properties are made with no further adjustment of the model. We successfully predict relative permeability and oil recovery for water-oil- and mixed-wet datasets. For waterflooding we introduce a method for assigning contact angles to match measured wettability indices. The aim of this work is not simply to match experiments, but to use easily acquired data to predict difficult to measure properties. Furthermore, the variation of these properties in the field, due to wettability trends and different pore structures can now be predicted reliably.
Using a Dynamic Mechanical Earth Model and Integrated Drilling Team to Reduce Well Costs and Drilling Risks in San Martin Field
Authors: Lee Donald , Cassanelli Juan Pablo , Frydman Marcelo , Palacio Julio , Delgado Roger , Collins Bryan
Published: December 2007

This paper briefly describes a process developed to reduce drilling risks and well costs and gives details on its application to three deviated development wells in Camisea, Peru. Previous offset vertical and deviated wells in this area encountered wellbore instability, drilling fluid loss, and reactive shales. In some cases these events made it necessary to drill multiple sidetrack wells.

The process provided specific advantages while drilling technically difficult trajectories. Integral to the process was development of a mechanical earth model (MEM) for prediction of drilling events and down hole drilling risk management. The model, created using data from multiple disciplines (seismic, drilling, geology, wireline logs, core testing), enabled the drilling team to understand potential drilling hazards and quickly act to mitigate risks, as well as to make rapid informed decisions while drilling. Examples demonstrate how the process compared forward predictions with actual results and how the model was updated during drilling.

The first well reached total depth (TD) 5 days ahead of schedule even though the trajectory was in a difficult stress azimuth and several nondrilling problems occurred. Teamwork and communication among the drilling location and four offsite offices played a critical role in the decision process. Predrill predictions matched post-drill information in most cases. Lessons learned from the first well were applied to subsequent well plans.

This process can be applied to any exploratory or development well, but high-risk, high-cost wells receive maximum benefit. Although wellbore instability resulting from tectonic stress was the main risk in this field, the process is equally valid for drilling issues such as overpressured regimes, underbalanced drilling or extended-reach wellbores.
Cost Effective Competency: An Approach That Works
Authors: Lovelace Perry
Published: December 2007

This presentation will provide delegates with a sound basis for supporting and implementing a Competency-based training program, and how it can deliver valuable, measurable benefits. Developing competent professional staff is receiving renewed management attention and many technical new-hires need to be productive quicker for less cost, especially in developing nations. Many companies have devoted considerable resources to understand and improve staff competencies; few can tell if their training programs have a real impact on the bottom line. We will present an approach that has broad Petroleum Industry backing and is delivering successfully. Competency Maps for Facilities Disciplines will be shown as examples and their utilization explained using real on-the-job examples. The presentation will include examples of Return-on-Investment evaluation, assessment techniques and gap analyses, progression matrices, individual competency tracking using web-based applications and industry applications. A case study of how BP is realizing success, being challenged, and planning for the future with its Competency-focused training investments will provide a valuable example.
Reservoir Monitoring with the CHFR in Water Injection Reservoirs, Libya Eamples.
Authors: Tchambaz Mohamed , Belhadj Belkacem
Published: December 2007

The increase of the recovery efficiency combined with an optimized production and a representative modeling require a reliable reservoir monitoring techniques.

Recently introduced in Libya, the CHFR (Cased Hole Formation Resistivity) has provided an accurate saturation profiles through casing by deep resistivity measurements. This paper presents two field cases of oil producer wells, the reservoir monitoring with the CHFR highlights the importance of this exhaustive investigation. A comprehensive understanding of the reservoir water flooding is achieved, allowing to select the appropriate remedial options for the water-cut reduction.

The first example presents a multi-reservoir under water table drive in a moderate permeability anisotropy. A comparison of the saturation profiles completed between the original open hole and the CHFR-Plus evaluations has detected the oil-water contact rise and brought a valuable information for the distribution of the remaining potential oil.

The second example deals with a lateral water injection on a multi-layered reservoir having a different ranges of permeability. The reservoir monitoring has located the water-swept and depleted zones according to the saturation profile changes.

In both cases, the remedial operations based on the CHFR-Plus investigation results have allowed a significant enhancement of the oil production and the implementation of the optimum field management strategy.
Designing Fibered Cement Slurries for Lost Circulation Applications: Case Histories
Authors: Low Nick , Daccord Gerard , Bedel Jean-Philippe
Published: December 2007

Lost circulation problems are often encountered when drilling or cementing highly permeable formations (e.g., sandstones), naturally fractured formations (e.g., limestones), or through depleted zones. Curing these problems is critical if the operator is to control the well and drill and complete it effectively. Failure on a primary cement job due to lost circulation not only increases well costs but also can jeopardize well integrity.

The use of cement plugs to cure the losses is well-known, and these plugs are often used as a last resort. Lost circulation materials (LCM) are usually added to the cement slurry to maximize the chance of successfully stopping the losses. LCM can also be added to the cement slurry during a primary cementing job if losses are expected in a particular well section. However, the design of such cement slurries is not obvious and may not completely solve the problem. It is often uncertain whether the use of an LCM will help to completely cure the losses. Lastly, the appropriate LCM is often difficult to identify.

This paper shows that it is possible to formulate effective cement slurries to solve most lost circulation problems. The technology can be used either for a cement plug or during primary cementing operations by adding specifically designed fibers in a controlled manner. A laboratory setup was built to evaluate the fibers’ efficiency in this application. We present the main results obtained and discuss the mechanism of action of the fibers. We also show that the combination of an enhanced particle size distribution cement slurry with this specific type of fiber allows the use of ultralightweight slurries, which leads to even better control of the losses and therefore increases the likelihood of success. These systems can be pumped with the standard cementing equipment used for typical primary cementing jobs. Several recommendations are made on the most effective way to use the fibers. We present Case histories that demonstrate improved slurry placement in traditionally difficult situations.
Development of a Petroleum Contractual Strategy Model
Authors: Ramadan N. B. , Zekri Abdulrazag Y.
Published: December 2007

The development of a petroleum exploitation strategy is essential for any country, which needs to develop its indigenous petroleum resources. A petroleum exploitation strategy is the series of policies relating to licensing, taxation, royalty, and general legal instruments i.e. contractual agreements. Contractual agreements developed by the state in order to ensure the orderly development of petroleum exploration and production. In the absence of a clear petroleum exploitation strategy, the international oil companies would not be able to assess the political and economic risks involved in any petroleum exploitation venture, no matter how low the technical risks are.

Since the International Oil Companies are major sources of the intensive capital, and sophisticated technologies needed for exploration and development of petroleum resources, it is essential for a country to formulate a coherent and well-balanced petroleum exploitation strategy. This should be consistent with its social and economic goals and at the same time allow the international oil companies to generate economic profits that in some way relate to the level of risk involved in obtaining these profits. This research project has focused on the study of the different petroleum contractual agreements between host countries and international oil companies worldwide, and has culminated by the development of a contractual strategy model for the exploitation of the petroleum resources. The development of the model has been preceded by a comparative and evaluative analysis of the international and host country petroleum agreements. The main features, advantages and disadvantages of each type have been summarized and tabulated. The suitability of the different agreements, in the view of the rapidly changing environment of the petroleum industry, has been evaluated. The Model required the development of eight different strategies, which relate to the possible combinations of three strategic factors that were found to be of the greatest importance. It has been proposed to use this model to evaluate and guide the development of the future Middle East petroleum exploitation strategies.
Experience With Operation Of Smart Wells To Maximise Oil Recovery From Complex Reservoirs
Authors: Snaith Nigel , Chia Richard , Narayasamy Devarajan , Schrader Kirby
Published: December 2007

Selective completions have been used in BSP's Iron Duke and Bugan fields to allow commingled production from multiple reservoir intervals, in some cases across fault blocks. Typically, the oil rims in Iron Duke and Bugan are overlain by large gas caps within heterogeneous sandstones. Recent PLT results have indicated that gas breakthrough occurs in high permeability sand streaks. As a result, selective production offers the potential to increase ultimate recovery by improved reservoir management. For example, specific simulation models built to investigate the benefits of a smart well have estimated 20% increase in UR in the Iron Duke. In addition, smart completions offer the potential of accelerated production.

The benefits of smart completions are discussed with particular reference to the well Iron Duke 19. This was completed with a 5 zone selective completion. Although the production performance of 3 of the 5 zones was worse that expected, the smart completion has demonstrated considerable value in allowing both production rates and expected ultimate recovery to be increased. This shows that much of the value of selective completions can be in providing flexibility to respond to reservoir surprises.

Some of the challenges that have been encountered with the operation of multi-zone selective completions and the solutions that have been put in place to optimise well and reservoir deliverability are also discussed. This experience builds on that described earlier for the much larger Oseberg field in Refs. 1 & 2.
Hybrid Testing Technique Results in Successful Well Test and Completion of Low Permeability, HP/HT Sour Crude Reservoirs - A Case Study from Kuwait
Authors: Reji E. C. , Al-Awadi Mohammed , Al-Medhadi Fahed , Kaura Jiten , Clayton Robert
Published: December 2007

The development of light-oil reservoirs in Kuwait has become increasingly more important for maintaining the quality of exported crude. This is due to the fact that producing light-oil reservoirs has proven to be not only a necessary link for maintaining the oil production from this area but also for increasing it. As a result, efficient testing of the light-oil reservoirs has become paramount in importance for overall well and field development.

The reservoirs in Kuwait are low permeability, high pressure/high temperature (HP/HT) and sour. In earlier wells, the strategy had been to perforate these formations balanced or slightly overbalanced, in mud, with through-tubing guns. Results from testing in several wells indicated that if they could be perforated under-balanced, the formations would yield better results since this method would allow better penetration and perforation cleanup. A number of reservoirs are stacked horizontally and range from typically conventional to fractured limestone.

In view of the corrosive nature of the fluids present, one of the primary efforts in the testing of these wells had to be directed toward keeping the number of wireline and coiled-tubing operations to a minimum without compromising the testing objectives. Since it was necessary to test multiple objects in the exploratory wells individually, special effort was focused on determining methods that could effect a reduction in the testing period for each object. By reducing individual testing times, Kuwait Oil Company felt that the overall savings would be significant.

Several areas were identified that would require special consideration. This paper will discuss these areas (listed below) and how the challenges they presented were addressed: Modifications to retrievable completion test (RCT) tools and tubing-conveyed perforating (TCP) equipment that would be required to test these zones efficiently.The challenges associated with designing and carrying out the tests.Ongoing modifications in the testing methodology to overcome the testing challenges.The operation of the test-string, annulus-pressureresponsive components in the heavy oil-based mud and the difficult wellbore conditions.How the problems of shaped charge performance in the naturally fractured formations with unusually high compressive strength and very low matrix permeability and porosity were resolved.

The modifications to tools and methods allowed the goals of the operator and service provider to be met.
Laboratory Investigation and Field Use of a Novel Sand Cleanout Fluid System for High Temperature Applications
Authors: Xiao Zhijun , Shahin Magdy , Hosein Paul , Dellorusso Paul , Lungwitz Bernhard , Samuel Mathew
Published: December 2007

Cleanout of proppants, cuttings and fines in well construction and production phases are typical of oilfield operations. To make these processes successful, extensive research efforts have been done on the development of (i) equipment such as concentric pipe, tubing-operated pump-to-surface bailer and coil tubing with jetting; (ii) engineering operation control and software simulation such as conventional high-rate circulation, reverse circulation, three-segment hydraulic modeling; and (iii) carrier fluids with suspension capabilities. The development of equipment is generally expensive, and often operation limited. Software simulation and control of operation parameters are normally not able to achieve the expected cleanout effectiveness due to the process complexity. Development of novel fluid systems is the only way forward to simplify the cleanout puzzle, and extensive research has been done to improve the efficiency of carrier fluids. The most commonly used fluids are brines, drilling fluids, foams and viscous polymer fluids.

The paper describes the laboratory development of a novel viscoelastic surfactant-based cleanout fluid system and its successful field application. This fluid has several advantages over conventional polymer systems. Viscoelastic surfactant systems are non-damaging to the reservoir, has excellent suspension capacity, adjustable density for hydrostatic head and low friction.
Application of a New Class of Surfactants in Stimulation Treatments
Authors: Nasr-El-Din Hisham A. , Samuel Elsamma , Samuel Mathew
Published: December 2007

Different acid systems have been used to stimulate production and injection wells for more than a century. Several chemicals are added to the acid to enhance the efficiency of the acidizing treatments, including various types of surfactants.

Surfactants play a key role in many well treatments because of their unique properties. Surfactants are used to reduce surface tension, change wettability, mobilize residual oil, and disperse corrosion inhibitors. They are also used as anti-sludge agents, emulsifiers in acid-oil emulsions, and demulsifiers. This wide spectrum of applications is due to the ability of surfactants to adsorb on various surfaces and associate in the bulk of solutions and form micellar structures. The properties of surfactants depend on the size of the head, tail length, and configuration of the tail, surface charges, ionic strength and temperature.

Recent advances in surfactant technology have introduced a new class of surfactants with special characteristics useful in oilfield applications. This new class of surfactant has the ability to form viscoelastic systems, which can be used to increase viscosity of the treating fluids, without causing formation damage. These surfactants have been used in Saudi Arabian fields to enhance diversion during matrix acid stimulation, reduce leak-off during acid fracturing and to minimize losses (well control) during workover. The system proved successful to provide fracture extensions in acid fracturing applications of low temperature seawater injectors and high temperature gas wells. These surfactant systems are non-damaging and do not require sized solids to control losses, which eliminates the need for remedial acid treatments.
Innovative Inflatable System Enables the Underbalanced Deployment of Sand Control Screens
Authors: Arnold George , Suwandi Enrico
Published: December 2007

A recent project in the Asia-Pacific country of Brunei required the underbalanced deployment of sand control screens into two wells immediately following the completion of their underbalanced drilling. An inflatable system was specially developed for use in this application to overcome the challenge of maintaining well control while deploying the screens. After serving as a primary barrier while the screens were run into the well, the inflatable tool was then released by the run-in string, and pushed to bottom; a task that would pose a significant challenge to existing inflatable technology. The new system integrated specialized accessories with fieldproven inflatable tools and techniques to enable the innovative procedure.

The paper will summarize the system design process, showing how project engineers addressed the limitations of previous methods with new, inflatable accessories and running procedures. The authors will also present a detailed description of system components including running tools, inflatable tools, releasing tools and their operation. Finally, the paper will review the implementation of this new technology by summarizing the application from the pre-job planning process through the installation of the equipment at the well-site.
The Alphabet Soup of IOR, EOR and AOR: Effective Communication Requires a Definition of Terms
Authors: Stosur George J. , Hite J. Roger , Carnahan Norman F. , Miller Karl
Published: December 2007

The purpose of this paper is to call attention to the need to establish a mutually acceptable definition of the terms Enhanced Oil Recovery (EOR) and Improved Oil Recovery (IOR). It is hoped that the SPE will take note of the need to define the terms and use them as guidelines in reviewing of manuscripts for publications and presentations at its worldwide SPE meetings. A workable definition of the terms is necessary not just for improved communication, but also for recoverable reserves, contract negotiations, Government incentives, taxation purposes, and regulatory authorities when looking at fiscal issues. To get the discussion started, the authors propose workable definitions of the IOR and EOR terms based largely on an informal survey within the SPE EOR/IOR Technical Interest Group (EOIO TIG).
First Successful Implementation Of Expandable Sand Screen (Ess®) Technology In An Open Hole Horizontal Well Located In Baram Field, Offshore Malaysia – A Case Study
Authors: Kabir Mir Rezaul , Awang M. Zaki , Umar L. , Norjusni Omar , Khazimad Yusof
Published: December 2007

During the second quarter of 2002 Petronas Carigali, the State Oil Company of Malaysia, embarked on a campaign to utilize Expandable Sand Screen (ESS®) in unconsolidated multi-zonal sandstone completions in the Baram and Alab fields, offshore Malaysia. The primary objective of the application of ESS® technology was to control sand in conjunction with minimum skin damage without encountering operational problems/constraints which are inherently associated with gravel packing as a means of sand control. A total of five deviated cased holes were equipped with ESS® with mixed results which have been documented in details in a previous publication by the authors (SPE paper # 80449). Further investigation revealed that the wells completed with ESS® have achieved satisfactory improvement in productivity. ESS® technology has now proven to be one of the best available sand control techniques for the Baram field.

This paper will focus on Petronas Carigali’s experience in ESS® technology implemented in a deep horizontal open hole section of a sandy well which is to be equipped with a gravel pack assembly in the upper section inside the cased hole section, thereby providing an excellent source of comparison between the performance of gravel packing and expandable sand screen technology. Installation of ESS® in well BA-47, being the first deep horizontal open hole application in Malaysia, was an operational challenge with a few lessons learnt which may be shared by other operators.

The primary objective of the well has been successfully realized as evidenced by better than expected sand free production. The execution of ESS® installation was successful with some problems encountered while initiating the expansion process. After some modifications on the expansion string and mud/brine system, the expansion process was carried out smoothly.

The secondary objective of the ESS® application was to assess/evaluate the enhancement/impairment of productivity of the well using ESS®, in comparison with the technique of gravel packing. The well is presently in the process of being cleaned up. Preliminary data indicates higher than expected production. PI and PBU tests are planned for the well as soon the well has cleaned up and/or stabilized.
Stimulation Through Back Surging In Horizontal Wells In Mumbai High Field
Authors: Siddiqui N. A. , Roy K. K. , Kumar O. V. , Hazarika A. K.
Published: December 2007

The CTU based stimulation jobs practiced for the horizontal oil wells completed in the, LIII limestone reservoirs of giant Mumbai High field in the Western Offshore basin of India was gradually losing its desired efficacy due to the falling reservoir pressures. As an alternative, the back surging technology used for post gravel pack perforation tunnel cleaning operations in sandstone reservoir was recasted with minor modifications and applied for stimulating the horizontal wells in the saturated, multilayered LIII reservoir Wells IQ-9H and S16-P1H located in the downdipside and crestal part and of the field respectively, were identified for pilot tests so that the field trials are subjected to widely differing geological and petrophysical environment. While Well IQ-9H is placed in the thin uppermost layer of LIII limestone overlain by a huge shale sequence, well S16-P1H is placed within an intermediate layer of the same limestone formation overlain by a large gas cap in the upper eight layers and underlain by a shale band. Encouraging results in both these wells prompted more extensive use of the technology elsewhere in the heart of the field, and results of around twenty 8–1/2" horizontal sections and forty-one 6" drain holes completed in the last three years have been deemed to be successful without exceptions, both in terms of effective stimulation and rig-time savings to US $ 30,000 /well , thereby proving to be a cost effective substitute over conventional bulldozing and CTU based jobs.

The surge tool is tailormade for instantaneous drawdown across the formation face thereby removing all post-perforation fines. The assembly is run on a lock mandrel to an appropriate landing nipple profile. The tool is surface dressed with shear screws, number and type chosen to suit the pressure likely to be created across it. After the horizontal well is completed with packer, the dressed back surge assembly is installed over the landing nipple through slick line. The tubing volume above the back surge tool is knocked out for creating the differential pressure. The preinstalled shear pins gives way to the formation fluids. The back surge tool is ultimately retrieved once the stabilised flow is attained.

The paper details the design of the surge tool, its preference over other existing systems in practice and the performance enhancement profile alongwith the financial indices in the 61 wells it has been tested in the LIII reservoir of Mumbai High field.
Fastest Deep Marrat Well in North Kuwait: Case History of Raudhatain 206
Authors: AL-Saeedi M. , AL-Mutairi B. , AL-Khaldy M. , Sheeran T.
Published: December 2007

For the last 20 years, exploration in Kuwait has focused on finding commercial quantities of high quality oil in the deeper high pressure/high temperature (HTHP) Jurassic formations (13,000–17,000 ft), and for gas within the Triassic formations (17,000–21,000 ft). The HPHT conditions, the presence of H2S and CO2, the narrow pore pressure/fracture pressure (PP/FP) window to work with, and the high mud weights (18–20 ppg) required have made deep drilling conditions in Kuwait some of the most challenging in the world.

This paper discusses the outstanding drilling performance achieved in drilling Ruadhatain 206 (RA-206) as the fastest deep Jurassic well to date in North Kuwait. New practices were incorporated and several firsts accomplished through optimum utilization of local built-in experience, combined with the latest technology and practices developed by International Operating Companies (IOC's) and service companies.

Optimum bit selection resulted in a world record bit run in the 28" section, and record firsts for Kuwait in the 22" and 16" sections. Careful analysis of offset data and in selecting mud weights resulted in improved hole stability with minimum mud losses, and enabled the bottom two hole sections to be commingled. Extensive cement design and optimization resulted in an excellent CBL being achieved in the production casing.

The excellent performance achieved in well RA-206, has now opened the possibility of efficiently drilling similar wells in 100 days (technical limit) instead of the 170–200 days normally taken. (Fig-1) The improved drilling practices significantly reduced the drilling time and well costs, and provided a step-change forward in KOC's understanding of drilling limits when applied to deep exploratory/development wells.
New Contracting Relationship Improves Drilling Performance with New Technologies and Aligned Goals
Authors: Forbes David , Mencer Glenn , Hartono Slamet , Russell Richard , Stymiest John
Published: December 2007

Dubai Petroleum Company (DPC) operates a number of offshore fields in the emirate of Dubai in the United Arab Emirates. The fields have been producing for over 30 years and the structures now require some of the most innovative and complex well designs that are currently being drilled in the industry today. In order to successfully achieve such designs it has been necessary to introduce new processes and technologies. DPC recognized that traditional contracting relationships were not the appropriate environment to encourage the use of such technologies to improve the drilling performance.

In 2002 a new contracting relationship was established between Dubai Petroleum Company and Halliburton for the provision of directional drilling, MWD, LWD, drill bits and Surface Data Logging (SDL) services. Whereas previously these services were provided by four different suppliers, it was recognized that they are all related in terms of the provision of data and performance during the drilling process. It was therefore determined that synergies would be realized by having these services provided from the same source. More importantly a fair and equitable remuneration scheme was established whereby overall compensation was based on agreed key drilling performance factors, in addition to meeting agreed well objectives. These are designed in such a way to allow the service supplier to realize the benefits of introducing new technologies which in turn would actively encourage their introduction.

To date the new contracting relationship has been in place for over a year and it is now possible to compare drilling performances under the new contract with those under the previous contracts. In addition during this period a number of new technologies have been utilized in the drilling of these wells.

This paper will examine the traditional contracting relationship between operator and service supplier and describe the new contracting relationship established in 2002. Previous and current drilling performances will be compared and the new technologies introduced described along with the benefits they bought to the overall drilling program.
Field Study in Kuwait
Authors: Al-Zanki Khalid , Al-Anzi Nayef , Cox Gene , Al-Mohailan Mohannad , Al-Khaldy Ali
Published: December 2007

After the liberation of Kuwait, a large number of wells were blown up by the Iraqi troops, and some needed to be worked over before re-producing them. Around 100 wells were intact and were put back on production shortly after the liberation. Those wells are originally 40 to 50 years old, and the wellhead equipment on those wells were not changed or reconfigured with the current API standards until this date. Workover operations were delayed due to several issues concerning the wellheads. A project was assigned by KOC management in 2002 to inspect those wellheads and submit a report with the current status of the equipment, problems, and solutions.

As a result of a full research made on those intact wells, the wells were segregated into 4 categories depending on the integrity and operational issues of the wellhead equipment. It was decided that some of those wellheads would only be reconfigured using a combination of the old and new equipment. Others will require total wellhead replacement.

This paper will discuss results and recommendations on the report submitted. It will cover the integrity issues of old wellheads concerning safety, control, and effect of time on the equipment. It will also cover the operational issues on those wellheads that prevented safe and controlled workover operations. Improved technology was the ultimate solution, and a detailed comparison between the old and the new types of wellheads will be discussed in the paper.
Drill Cuttings Disposal, Balancing Zero Discharge and Use of Best Available Technique
Authors: Paulsen John E. , Omland Tor H. , Igeltjørn Hilde , Aas Nina , Solvang Steinar Aabye
Published: December 2007

The new OSPAR regulation (OSPAR 2000/3) on drill cuttings is due to be effective by January 2005 at the Norwegian continental shelf. Drilling operations planned to be performed from to date and onwards therefore have to take into account that the forthcoming regulation has important implications with respect to selection of adequate and compliant technology.

Drilling will commence at a new HTHP Statoil operated field offshore middle Norway, by late summer 2003. Ahead of the spudding in, a detailed and comprehensive review of technological solutions has been carried out to resolve the issues of zero discharge and use of best available technique.

The paper describes the challenges associated with the forthcoming zero discharge regulation and the different technological scenarios that have been reviewed. Waste minimisation methodology has been of major importance in the decision process. Treatment of oily drilling waste, applying new technology at the rig, was studied in detail. The respective energy budgets, environmental impacts and risks associated with the different solutions are also presented, as well as a suggested best technique.

The paper offers a study of how operators may comply with a zero discharge in drilling operations, with reference to BAT (best available technique). On a general basis the ultimate goal of environmental legislation is discussed with reference to the forthcoming discharge regime and how to decide BAT; achieving the right balance between technology and value.
Drilling Fluids Approaches for Control of Wellbore Instability in Fractured Formations
Authors: Labenski Franck , Reid Paul , Santos Helio
Published: December 2007

The presence of microfractures is now recognized as a common cause of severe wellbore instability, particularly in ultra-low permeability rocks such as shales and some limestones.

In unstable microfractured formations, it is important to avoid pressurizing the fractures with drilling mud. This paper examines the rock mechanics aspects of wellbore instability in microfractured formations, and identifies drilling fluids and drilling practices that reduce the problem. Improved stability can be achieved by the use of certain drilling fluid additives that seal fractures. Limited success is seen with sized solids, asphalts, gilsonites or conventional lost circulation materials but a recently developed additive for use in oil- or water-based muds appears to prevent much of the instability normally observed.

The mechanism of action of this additive is discussed and a recent field case history presented.
Geosteer with Resistivity Forward Modeling to Prevent Drilling into the Loss Circulation Zone of a Prolific Carbonate Reservoir
Authors: Kok Keng H. , Pruimboom John , David Frank M. , Jit-Chiun Then
Published: December 2007

The field development plan for a Sarawak Shell Berhad operated gas field, located in the South China Sea, offshore Sarawak, Malaysia, specified drilling of horizontal wells into the Tertiary Miocene Carbonate reservoir. The wells were planned as high capacity producers of the Big Bore-Long Casing Flow design.

The traditional well design dictated that, prior to entering the reservoir, a casing had to be installed to stabilise the hole in soft shale. The uncertainty of detecting the formation top resulted in premature casing commitment of at least 30 feet TVD above the top of the reservoir and the need to use an expandable liner to cover 300 feet of exposed shale above the reservoir.

To obviate this problem, the capability of one of the components in the Logging-While-Drilling tool array, namely the Electromagnetic Wave Resistivity forward modeling technique, was used to detect the top of the carbonate formation (top reservoir), immediately prior to drilling into it. A standard Logging-While-Drilling tool is configured to prioritize Electromagnetic Wave Resistivity forward model response as the carbonate formation top is approached. This configuration, together with an appropriately designed bottom-hole-assembly and well trajectory, enabled the successful implementation of the plan to stop drilling approximately one foot true-vertical-depth above the carbonate top.

At this point, a conventional 9 5/8-in. casing string was set at an optimum depth. This eliminated potential well control problems, costly remedial actions associated with lost circulation and inferior cementation of the 9 5/8-in. casing string.

Thereafter, the wells were drilled horizontally in a conventional manner, into the carbonate gas reservoir.

This paper compares pre-drilling Electromagnetic Wave Resistivity forward modeling of the proposed well trajectory with the actual well data, whilst drilling. The pre-drilling and post-drilling modeled data is presented.

The cost savings from employing this technique are variable, ranging from substantial - in the event of a well control situation and attendant high losses - to moderate if the need to set an expandable is eliminated.
Analysis of Hook Load Data to Optimize Ream and Wash Operations
Authors: Freithofnig H. J. , Spoerker H. F. , Thonhauser G.
Published: December 2007

Monitoring the borehole condition during the ongoing drilling process is essential for a successful and safe drilling operation. The drilling industry has developed monitoring systems, which offer the possibility to analyze torque and drag effects in real time and typically calculate a borehole pseudo friction factor.

The paper presents a new approach of analyzing recorded drilling data by directly using hook load measurements. The target of the analysis is to minimize the time spent on ream and wash operations. Furthermore the proposed method can be used as an indicator of developing borehole problems at an early stage before they become critical to the operation.

The method is based on the comparison of the hook load during pick-up and slack-off movement of the drill string while reaming one stand of drill pipe prior to making a connection. A characteristic signature is generated, which is then interpreted automatically.

The result shows whether the well bore conditions allow to resume operations or indicate continued reaming, thus optimizing the number of reaming trips and subsequently reducing the total amount of non-productive time.

Based on the comparison of ream and wash sequences of subsequent drill pipe stands, it is possible to generate an automatic well bore condition log, which shows well bore sections with abnormal behavior.

The paper shows that it is possible to identify non-problematic well bore conditions and to avoid unnecessary ream and wash operations.

A software package offers the possibility to post analyze recorded data as well as the evaluation of real-time data. A case study shows the technical and economic potential of this new approach.