bluuebunny/crossref_metadata_2025 huggingface dataset:
Steamdrive Stability in High Porosity Rock
Authors: Hoffman B. Todd , Kovscek Anthony R.
Published: December 2007

Steamflood displacement is considered to be stable, as compared to other gasflooding techniques. Stability on the microscopic and core scale is thought to lend stability to steam movement on the reservoir scale. High mobility displacing agents tend to "finger" beyond the front, but this effect is suppressed for steam by condensation within the finger as steam contacts lower temperature reservoir. Heat transfer from the steam to the surrounding connate water, oil, and rock is the primary mechanism to ensure stability. Because most reservoirs have a significant proportion of rock (70%-80%), there is sufficient thermal mass to cool any steam fingers. However, when the porosity is high, there is less rock to dissipate heat; therefore, less suppression of viscous instabilities. Depending on the porosity and other reservoir properties, the typical assumption of stable steamflood displacement may not be valid. Initial aspects of this work use analytical methods to examine frontal stability in high porosity rocks. Analytical methods indicate stable steam fronts for typical reservoir properties, but they also predict unstable displacement in high porosity rock.

The second portion of this work uses pattern level thermal simulation to study the stability of steam drives in high porosity rocks. Two different permeability models (an isotropic model and a thief model) are compared at three porosities (25%, 50% and 70%). Low rock thermal conductivity is shown to reduce the suppression of the steam fingers. More importantly, the simulation results show that as the porosity increases the stability does decrease. This is exemplified by shorter breakthrough times for the higher porosity models. While the stability of a steam front does decrease, the difference is likely not very significant, around a 20% reduction in breakthrough time, compared to other aspects. For example, reservoir heterogeneity has a much greater impact on breakthrough time than the relatively unstable displacement front associated with high porosity rock.
New Fluid Technology Improves Well Productivity in the Western 31S Stevens Oil Zone in the Elk Hills Field
Authors: Agiddi David , Davenport Brent , Hernandez Helver , Lockman Rusty
Published: December 2007

This paper presents a comparative well study performed in the central California Elk Hills field, Western 31S (W31S) Stevens Oil Zone. Stimulation of the W31S Stevens Oil Zone using hydraulic fracturing with conventional polymer fluids is compared with the use of a new viscoelastic high performance fracturing fluid (HPF).

The field development of the W31S zone was initially completed with conventional fracture-stimulated treatments containing borate crosslinked guar polymer and encapsulated oxidizing breakers. Although a positive production response was observed, additional production improvement was desired. Post-fracture tracer logs indicated that improvements could be made by achieving better net fracture height coverage. In addition, post-fracture acidizing treatments indicated that the fracture fluid polymer had damaged the propped fracture conductivity.

Recent development in fluid technology has resulted in the introduction of a unique, patented fracturing fluid that provides the following benefits: Less damaging to the formationExcellent proppant transportability, resulting in improved net fracture height coverageRequires no breaker additivesRecyclable

This HPF fluid was compared to conventional borate crosslinked polymers, a crosslinked CO2 foam fluid, and a high pH borate crosslinked polymer with an enzyme breaker. The case histories show better production rates with the new HPF fluid. Also, despite very robust and stable rheological properties during pumping, this new fluid returns to its original viscosity shortly after closure, with no internal breakers. The unique properties of this fluid are discussed, along with case history information, in the remainder of this paper.
An Attractive Raw Deal – Novel Approach to Barton Oilfield Water Injection
Authors: Lee Steven Kiong-Hooi , Tan Thiam-Guan , Vaughan Andrew
Published: December 2007

This paper describes the integrated subsurface/surface concept generation and challenge process which delivered a novel water flood project (raw seawater injection), slashing 60% off the original engineering Capex, while still addressing key subsurface uncertainties, and keeping within the normal project timescale. It also attempts to identify the key factors and processes that helped to deliver this innovative solution in spite of the challenges.

The processes described in this paper allow for early surface/subsurface/well engineering engagement in order to promote creativity and manage uncertainties in challenging E&P projects. Managing such creative, parallel processes has allowed the Barton team to be better integrated in finding an optimal and novel solution to a complex situation, hence positioned to deliver higher value within a reasonable timescale. The team acknowledges the value of a structured process to generate widely divergent solutions (which look like chaos at the time), and the creative tensions and discomfort that accompany shifting through this chaos to deliver an innovative solution. It also described the means in which the team had built stakeholder support for new ideas through engaging global expertise.
Experimental Design and Analysis Methods in Multiple Deterministic Modelling for Quantifying Hydrocarbon In-Place Probability Distribution Curve
Authors: Peng Cheong Yaw , Gupta Ritu
Published: December 2007

This study addresses a few issues regarding the experimental design and analysis (EDA) methods, and its applications in multiple deterministic modelling to quantify hydrocarbon in-place (HCIIP) probability distribution curves. They include (1) the suitability of using Latin Hypercube design (more than 3 levels in the input variables) compared with the 3-level fractional factorial designs (FFD) (e.g. 2k-p FFD with centre & axial runs); (2) multidimensional kriging versus response surface method as the analysis technique to fit surrogate equation models; (3) the selection of test runs to evaluate the fitted surrogate equation models; (4) sensitivity of the assigned input probability values on the output response distribution curve; (5) the confidence interval of the cumulative probability distribution curve at median (P50) or other percentiles (e.g. P10 & P90); and (6) how to select representative 3D geological models at P10, P50 and P90.

In this study, an Excel spreadsheet, which mimics the 3D geological modelling workflow to estimate the oil in-place volume, is used to compare the above mentioned designs and analysis techniques. Some guidelines to select representative test runs/models to evaluate the fitted surrogate equation models are discussed. In multiple deterministic modelling, all the input uncertainties will normally be quantified with an uncertainty range from low, base to high values, and with their assigned probability values. Then, a decision tree can be built to visualise the full range of all the possible 3D geological models, and their respective probability of occurrence can be calculated from the probability of the input uncertainties. Combining the probability and the predicted responses from the evaluated surrogate equation model, the output response (e.g. oil in-place) probability distribution curve can then be built. Sensitivity of the input probability values on the output response distribution curve is briefly discussed. There will be some errors associated with the predictions from the surrogate equation models, and therefore confidence interval must be generated to account for them. With the P10, P50 and P90 output response values, the confidence intervals and the probability of occurrence, some representative 3D geological models at P10, P50 and P90 can be selected.

A 3D multiple deterministic modelling case study is then used to demonstrate the methodology in estimating the oil in-place distribution curve of a synthetic reservoir that is adopted from an actual fluvial reservoir.

In conclusions, the EDA methods can be used to minimise the number of 3D geological models that must be generated to build good HCIIP probability distribution curves. By using bootstrapping and normal confidence interval, fitting errors can be quantified and representative 3D geological models for P10, P50 and P90 values can be selected accordingly.
Digital Core Laboratory: Properties of Reservoir Core Derived from 3D Images
Authors: Knackstedt M. A. , Arns C. H. , Limaye A. , Sakellariou A. , Senden T. J. , Sheppard A. P. , Sok R. M. , Pinczewski W. V. , Bunn G. F.
Published: December 2007

A facility for digital imaging, visualizing and calculation of reservoir rock properties in three dimensions (3D) is described. The facility includes a high resolution X-ray micro-computed tomography system capable of acquiring 3D images made up of 20003 voxels on core plugs up to 5 cm diameter with resolutions down to 2 µm. Subsets of four sandstone reservoir core plugs (5 mm in diameter) from a single well of a producing gas field are imaged in this study. The four cores exhibit a broad range of pore and grain sizes, porosity, permeability and mineralogy. Computational results made directly on the digitized tomographic images are presented for the pore size distribution, permeability, formation factor, NMR response and drainage capillary pressure. We show that data across a range of porosity can be computed from the suite of 5 mm plugs. Computations of permeability, formation factor and drainage capillary pressure are compared to data from a comprehensive SCAL laboratory study on 70 cores from the same well. The results are in good agreement. Empirical correlations between permeability and other petrophysical parameters are made and compared to common correlations. The results demonstrate the potential to predict petrophysical properties from core material not suited for laboratory testing (e.g., drill cuttings, sidewall core or damaged core) and the feasibility of combining digitized images with numerical calculations to predict properties and derive correlations for individual reservoir rock lithologies.
Exploration Applications of Downhole Measurement of Crude Oil Composition and Fluorescence
Authors: Betancourt Soraya S. , Fujisawa Go , Mullins Oliver C. , Eriksen Kare Otto , Dong Chengli , Pop Julian , Carnegie Andrew
Published: December 2007

In addition to geological and petrophysical data acquisition during the exploration stage, in-situ fluid analysis provides a wealth of information for the appraisal of new discoveries. A recently introduced wireline sampling tool incorporating a downhole fluid analyzer is capable of analyzing fluid composition in real time at downhole conditions, and of measuring the fluorescence spectra of crude oils. These new measurements provide valuable information necessary for the identification and validation of reservoir structures that define the distribution of fluids in the accumulation. The relevance of high quality fluid data in the early stages of the producing life of the reservoir is widely recognized. We present field results of the application of the new sampling tool in an exploration well, where a composition gradient was detected along a 30m liquid hydrocarbon column grading from a 45API crude on the top to a 33API crude on the bottom. During the sampling of the gas cap, retrograde dew formation was detected identifying the fluid and identifying valid sampling conditions. This new information was used to modify the sampling program. Fluid composition analysis relies on optical absorption methods and is currently capable of providing the mass fraction of three hydrocarbon molecular groups: C1, C2-5 and C6+, and CO2. We perform fluorescence spectroscopy by measuring light emission in the green and red ranges of the spectrum after excitation with blue light. Fluorescence in this range is related to the concentration of polycyclic aromatic hydrocarbons (PAH’s) in the crude oil. Using the pump-out module to segregate different fluid phase enhances phase detection with fluorescence.
Methodology and Applications of A Multidisciplinary Reservoir Engineering Study for the Mature Oilfield
Authors: He Liu , Han Hongxue , Qunyi Wang
Published: December 2007

This article introduces the background and the methodology of a multidisciplinary reservoir engineering study that was carried out in Daqing Oilfield. The article focuses on the late stage of high water cut period multidisciplinary reservoir engineering study and the results of field application. The actual field application effectively improved the oilfield development and increased the recovery ratio.
A Workflow Approach to Life of Field Management
Authors: Yeow Lei-Ming , Nor Rosly Mohd , Lee Boo-Soon , Tsen Kin-Wei
Published: December 2007

Effective management of oil and gas fields over field life with the objective of maximising asset value can be a complex affair. Application and integration of various skills from subsurface (geology, geophysics, petrophysics, reservoir engineering, production technology and drilling) to surface engineering, production operations / surveillance and economics disciplines are required to manage technical, commercial and political challenges and uncertainties. In large organizations, there are the additional challenges of ensuring consistent work quality and process with multiple projects and technical personnel with different levels of skills and experience.

Subsurface and economic disciplines workflow over a field life from acquisition of exploration or development areas, exploration, development, production and abandonment work activities were mapped, improved and integrated to ensure work are executed more efficiently and correctly.

This paper describes the techniques and activities involved in developing this workflow which incorporates data and information management, technology mastery and promoting a collaborative and integrated multidiscipline approach. It was developed and deployed in two phases over 3 years and became the first web enabled workflow in the organisation. Pilot implementation was carried out on a number of domestic, international and outsource Field Development and Field Review projects.

Case histories of the application, benefits gained and lessons learnt are discussed this paper.
A Production Benefit Evaluation Program
Authors: Tang Wei , Zhang GuangJie , Sun JiPing , Chen YuHan , Guo FuJun , Xu Yan
Published: December 2007

Since 1998, we have launched a production benefit evaluation program at all 13 oil provinces. By classifying oil production according to benefit levels, we try to establish the concept of economic production and set the reasonable production target on the basis of economic benefit.

This paper describes the method of production benefit evaluation in detail. This production benefit evaluation program consists of developed oilfield evaluation and individual oil well evaluation. There are strict and detailed regulations on division of evaluation unit (for developed oilfields), selection of evaluation parameter and amortization of expenses. Also we introduce the progress of the production benefit evaluation program, evaluation results and its application.

Through this program, we get a good idea of the distribution of oil production in different benefit ranges and the status of operating cost. By taking adjustment measures, the operating cost of evaluation production have reduced greatly. As a practice of our low-cost strategy, this program is of great significance for controlling operating cost and enhancing economic benefit.
A Study on the Modelling of Knowledge Value Chain
Authors: Chen Yeong-Long , Yang Tzer-Chyun , Lin Zsay-Shing
Published: December 2007

The purpose of this study was to develop and apply a knowledge value chain (KVC) model. The model is based on Drucker's next society, Porter's value chain, Nonaka's spiral of knowledge, Kaplan and Norton's balanced scorecard, Gardner's multiple intelligences, and Pareto's 80/20 rule. An optimization technique is included in the model to identify the nodes (individual employees or groups of employees) of the critical value chain (CVC) and optimum value chain (OVC). The KVC model includes a business phase and a numerical phase composed of input knowledge, knowledge activities, and output goals. The input knowledge can come from intranet, extranet, and Internet channels and can be tacit and explicit. Whatever the source, input knowledge will converge toward an enterprise information portal (EIP). The value- added knowledge activities are based on socialization, externalization, combination, and internalization of knowledge. The knowledge value chain can be determined from output goals based on selected multiple values.

We applied the KVC model when analyzing employee value contributions at K Company in Taiwan. We selected five values (goals): customer, financial, learning and growth, internal business process, and innovation. The results of our application of the KVC model offered three key findings. First, the strengths and weaknesses of each employee's core competence were examined. Second, the critical nodes (winners' nodes or those of high-performance employees) for each goal were detected, and the selected critical nodes were gathered together to share their best practices. Third, optimum goals to reach the maximum value contribution to K Company were calculated.
Development and Implementation of Risk Based Inspection Methodology in Managing Inspection of Pressurized Production Facilities
Authors: Dewanto Kusmaryanto , Christian Rommy , Wibowo Ricky
Published: December 2007

VICO Indonesia operates in Sanga-Sanga, East Kalimantan produce gas and oil with approximately 1.0 BSCFD and 30,000 BOPD in 5 main plants; Badak, Nilam, Semberah, Mutiara, and Pamaguan. VICO Indonesia is continuously encouraged to reduce operating costs by minimizing operations cost and optimizing operability. One of the strategies is using Risk based approach methodology in carrying out inspection management for pressurized production facility. The objective of risk-based inspection is to ensure and maintain the required confidence of pressurized production facilities and maximizes its operating availability by planning of inspection interval and methods.

The basic steps of risk-based inspection are: –Creation and maintenance of asset register–Assessment of consequence and probability of failure–Creation inspection planning–Evaluate the inspection results–Review by risk based "team approach"

The feedback loop of risk-based inspection is essential for the continuous improvement.

This paper summarizes the experience in developing and implementing risk based inspection strategy for tackling the most failure mode in VICO Indonesia's pressurized surface production facilities. A description is given on how to focus inspection resources using risk based "team approach" involving inspection, operation and process engineers. A challenge of obtaining a reliable and cost effective inspection technique is also described. Finally, some useful lesson learned are included to prevent common problems from recurring, to stimulate the application of better practice and where possible to prevent or reduce the failure.
The Arun Gas Field in Indonesia: Resource Management of a Mature Field
Authors: Pathak Prabodh , Fidra Yan , Avida Hanifatu , Kahar Zulkarnain , Agnew Mark , Hidayat Dodi
Published: December 2007

The Arun gas field is a giant hydrocarbon resource in Indonesia and has been supporting Liquified Natural Gas (LNG) sales to the Asian market since 1978. The ultimate gas recovery is expected to be about 94% of initial gas in place, and the ultimate condensate recovery is expected to be a very high 87% of initial condensate in place. As the field has matured, reservoir pressure has declined and well productivities have declined. Mechanical wellbore failures have increased because of increased downhole stresses.The lower reservoir pressure has also increased the water vapor content in the gas, and producing wells have started to loadup as flow rates have decreased.

The application of new technologies has generated numerous opportunities to extend field life. Recent work has focused at maintaining productivity despite declining reservoir pressures. This paper presents a summary of Arun history and examples of recent resource management practices, including compression upgrades to reduce wellhead pressures, under-balanced drilling into a pressure-depleted reservoir and problem well restarts.
Challenges in Oil Production Technologies Affecting the Sustainable Development of Daqing Oilfield
Authors: Liu He , Yan Jianwen , Wang Qunyi , Sun Xishou
Published: December 2007

The paper introduces some problems that subdivision injection and production technology is facing in the stage of extra-high water cut production in Daqing Oilfield, the problems have become main factors affecting sustained development of Daqing Oilfield, like subdivision water injection, separate layer fracturing in thin restraining barrier and injecting surfactant to reduce pressure problem, each of them is close to challenge technical limit.
Formation Pressure Testing In the Dynamic Drilling Environment
Authors: Proett Mark , Fogal Jim , Welshans David , Gray Charlie
Published: December 2007

This paper introduces a new technology in which a logging while drilling (LWD) tool is used to pressure test a formation during the drilling process. The Formation Testing While Drilling (FTWD) or GeoTAP* tool described in this paper uses a testing technique similar to wireline formation testers. A probe is extended to the formation and a small sample chamber is used to pressure test the formation. The drilling environment offers many new challenges to pressure testing, however.

Wireline tools require a great deal of interaction with the engineer, which is very limited in the drilling environment. Therefore, the new tool has up-link and down-link capabilities and is highly automated for test control. New data compression routines are described that enable not only some of the raw data to be transmitted, but formation permeability (mobility) and test quality estimates to be obtained in real-time. An efficient algorithm is used down-hole to analyze the data where testing parameters and selected pressure data are transmitted to the surface in real-time for continuous monitoring of the test.

The drilling environment is more dynamic than is the case for wireline testers. Pressures in the borehole are constantly changing due to several factors. Invasion and the resultant supercharge effect can affect FTWD measurements. Supercharging results from mud filtrate invasion increasing the sandface pressure just behind the mudcake. Additionally it is desirable to keep the mud pumps on while testing to avoid hole deterioration and pipe sticking. Slower hydrostatic pressure changes can also occur due to drill pipe movement causing a swabbing effect. These pressure transients can be transmitted through the mudcake and into the formation. Using a newly developed near wellbore model that considers mudcake properties and invasion, these effects are simulated. A sensitivity study demonstrates the conditions that affect the stability and accuracy of the FTWD measurements.

Field data from the new GeoTAP tool are presented and compared with wireline formation test (WFT) data in test wells. The new tool requires the drill pipe to stop rotating/sliding for about 7 minutes per pressure test. During this time the pumps can be turned on or off. Most of the test results were taken with the pumps on. A "pumps on" GeoTAP tool field example is also presented, and the results compared very favorably with WFT data in terms of the absolute pressure measurement, repeatability and accuracy. The field example demonstrates the robustness of the measurement with three repeat pressure tests that were taken at three different depth points where, in each case, the pressures recorded were within 1 psi. Final conclusions are drawn regarding FTWD technology and its future direction.
Application of New Impregnated Diamond Bit Technology Saves Operator $2 Million Drilling Southern Oklahoma Well
Authors: West W. Cory , Roy Bryan J. , Knowles Steven P. , Wiesner Brian C. , Isbell Matthew R.
Published: December 2007

Economic development of deep gas wells, such wells in the Carter-Knox field in Stephens and Grady Counties, Oklahoma, depends on the effectiveness and efficiency of the drilling program. Many costly challenges are encountered while drilling the deep, high compressive strength, abrasive sandstone and interbedded shale in this geologically complex area with high-angle beds, faults, fractures, and depleted formation pressures. Improvements in bit technology have expanded the variety of formations that can be drilled with impregnated bits at penetration rates equivalent to roller cone bits. This technology has helped reduce the risk in drilling operations while improving well economics.

A recent well in the Carter-Knox field utilized three new impregnated bits to drill the interval from the third Bromide sandstone (15,000 ft) through the Arbuckle limestone and dolomite (18,700 ft) in 51 days improving well construction time by 35% over the best offset. Previous offset wells required 18 to 20 roller cone, natural diamond and traditional impregnated bits to drill the same interval in 78 to 155 days. The operator reached total depth 21 days ahead of the AFE and $2.07 million under budget. Reducing the dry hole cost more than 30% has positively impacted the development plans for the Carter-Knox field.

The operator and a bit manufacturer cooperatively applied new bit technology to an optimized well program to reduce drilling costs. Attention focused on using recently developed impregnated bits that drill shale at penetration rates equivalent to rollercone bits without loss of performance in the hard abrasive sandstone formations. This technology combined with changes in drilling practices has increased the overall average penetration rate, kept the bit drilling on bottom, and replacing multiple bits. The longer bit runs also reduced the number of bit trips limiting potential problems associated with tripping operations through depleted and sensitive formations.
Enhancements in Design Technology and Performance of Stable PDC Bits Revolutionize Hard Rock Drilling in East Texas Fields; Addendum to SPE/IADC Paper No. 79797
Authors: Fabian Robert T. , Johnson Simon , McDougal Fred
Published: December 2007

This manuscript is submitted as an addendum to SPE/IADC 797971, which discussed emerging successes using a new fixed cutter bit to drill hard rock applications conventionally drilled with roller cone bits. The new bit design using thermostable polycrystalline (TSP) diamond cutters and stability enhancing features has produced results, particularly in the Carthage field in Panola County, which are revolutionizing hard rock drilling in several areas of East Texas. The paper focuses on how teamwork, selective testing programs, and product improvements have combined to create step change improvements in hard-rock drilling capabilities. The paper discusses new information on optimal operating parameters and includes case history examples.
Analyses and Procedures for Kick Detection in Subsea Mudlift Drilling
Authors: Choe Jonggeun , Schubert Jerome J. , Juvkam-Wold Hans C.
Published: December 2007

In deepwater drilling a conventional large diameter riser requires drilling vessels with huge weight and space capacities, large mud volume to circulate through a riser, and many casing points because of narrow gap between pore and fracture pressures. A large number of casing points also require a larger wellhead and a larger marine riser. These problems are inter-related and intensify as the water depth increases. Although there are some successes to set a new drilling record on water depth, it is impractical to extrapolate current technology with a marine riser to 10,000 ft water depth.

Subsea mudlift drilling(SMD) is a term used to describe an unconventional technique using a relatively small diameter pipe as a mud return line from the sea floor instead of a large diameter marine riser. The scheme also balances internal and external pressures at the sea floor by reducing the internal pressure to make a dual pressure gradient possible. It has potential advantages of cost and time savings and rig upgrades for deepwater applications.

Kick detection and well control will not be hurdles for field applications of SMD. If the circulation rate is less than the maximum free fall rate, there will be a severe delay in kick detection. In this case, we may need to increase the circulation rate or use a drill string valve that provides a positive surface pump pressure. In case of transient U-tubing or fill up, we should avoid other operations for easy kick detection and well control, unless we have an accurate prediction and monitoring tool.
Delivering the Limit without Compromise: Understanding a True Operator/Contractor Value Partnership
Authors: Quintero Alan , Cockram Mark
Published: December 2007

This paper will outline how a long term relationship between a contractor and operator that integrates their safety cultures, provides incentives to the parties, and looks for ways to continually improve performance can lead to results that benefit both parties.

British Gas (BG) began an exploration program in the West Delta Deep Marine concession offshore Egypt in 1998, and hired the Atwood Oceanics rig Atwood Eagle to drill this initial program. The early exploration program was a success, and led to an exploration, appraisal and development program lasting 4.5 years and consisting of 36 wells drilled and eight wells completed with Atwood Oceanics rigs. The Atwood Eagle drilled 19 wells, the Atwood Southern Cross one, and the Atwood Hunter drilled 16 and completed eight wells.

HS&E performance was held in the forefront of the planning and execution of this program, and approximately 1.5 million man hours of rig operations were accomplished without a lost time incident (LTI). Details of how the safety cultures of the companies were seamlessly integrated will be discussed.

Also, as part of the drive to improve performance, BG's Total Value Drilling (TVD) initiative was executed for the Scarab Saffron eight-well completion program, the culmination of the entire rig campaign. The teamwork approach to operational improvement gained through the TVD process will be outlined.

The cooperation between Atwood Oceanics and BG led to excellent results that included:

A combined 1.5 million man hours achieved with three rigs on contract with BG, Rashpetco and Burullus (BG companies) in a challenging deep water drilling and completion environment. Drilling the first deep water exploration well in the area. The campaign included wells in water depths up to 3,430 feet. Best in class drilling performance compared to other operations in the area over 4.5 years without compromising safety. Operations that approached or surpassed the expected technical limit. Hiring and training of local employees into a world class safety program. No damage to the environment.
Invert Emulsion Fluids for Drilling Through Narrow Hydraulic Windows
Authors: Fimreite Gunnar , Asko Arne , Massam Jarrod , Taugbol Knut , Omland Tor Henry , Svanes Kaare , Kroken Wenche , Andreassen Espen , Saasen Arild
Published: December 2007

In mature fields the difference between the pore pressure and fracture pressure, expressed as the hydraulic window, is reduced. Underbalanced drilling and the use of low-viscosity drilling fluids are but a few of the many approaches that have addressed this challenge. While low-viscosity fluids severely reduce frictional pressure loss when compared to more viscous fluids, there is a limit to how much viscosity can be reduced before conventional weight material begins to settle.

This paper describes the development and application of novel technology that has resulted in a ten-fold reduction in the particle size of the weighting agent. With this development, invert emulsion drilling fluids can be designed with low viscosity with minimal settling potential of the weight material.

The authors will explain in detail the first field applications of this polymer-coated, micron-sized weighting agent in an oil-based drilling fluid. The system was used to drill two wells offshore Norway. These reservoir wells included an 8½-in. section and a 5⅞-in. thru-tubing section.

This novel drilling fluid technology delivers a low-rheology, low-sag fluid offering a number of performance benefits over conventional technology. Performance data from offset wells will be presented that show the benefits of this unique approach. Equivalent circulating densities (ECD) and torque values were significantly lower than comparable wells and no instances of particle settlement were observed.
Silicate-Based Drilling Fluids Deliver Optimum Shale Inhibition and Wellbore Stability
Authors: Soric Tomislav , Marinescu Pavel , Huelke Robert
Published: December 2007

Along with exorbitant costs and safety considerations, drilling an exploratory well where conventional mud systems could not maintain wellbore stability and trouble-free drilling, also posed the additionally difficult challenge of selecting a fluid system stable against multiple contaminants and flexible for a broad range of densities. The demands are compounded dramatically when designing the system and information to support the decision is poor.

This paper details the design and performance of a silicate-based fluid, which is an inhibitive mud system formulated with a soluble silicate for maximum shale inhibition. The system has been developed to drill water-sensitive reactive shales and dispersible chalk and illite formations. The degree of inhibition provided by the silicate system is significantly greater than any other water-based system, truly approaching the level of an oil-based system.

The authors will discuss the design and the application of the drilling fluid, which was selected to drill a formation containing anhydrite, claystone, dolomite and salt.

The system was formulated to be salt-saturated to avoid dissolution of salt layers; to withstand anhydrite contamination; to be flexible for densities up to more than 2.0 kg/dm3 while maintaining its high level of inhibition. Though comprehensive lab tests were performed, the possible depletion of silicate while drilling the anhydrite-containing formation remained. Nevertheless, this challenge was accepted with tight wellsite engineering planned to maintain the fluid properties.

Six wells have now been drilled with the proposed silicate system, with each showing very good performance and stable behavior in the above mentioned environment. The authors will present its effectiveness, formulation, properties, maintenance and lessons learned, along with the coordination and pre-planning that contributed to its successful application.
Alternative Aphron-Based Drilling Fluid
Authors: Growcock Frederick B. , Simon Gerard A. , Rea Anthony B. , Leonard Russell S. , Noello Eduardo , Castellan Rolando
Published: December 2007

A novel drilling fluid containing specially designed micro-bubbles -- "aphrons" – was recently introduced and has now been employed successfully in various parts of the world to drill through formations which previously had experienced uncontrollable losses and high incidence of differential sticking. The aphron-laden fluid appears to be particularly well suited for drilling through depleted zones. Wellbore stabilization is accomplished by (a) greatly reducing the invasion rate of the base fluid with additives that minimize the thixotropy of the fluid and enhance its shear-thinning character, and (b) reversibly plugging pores and fractures by the aphrons.

A recent innovation has permitted modification of the original fluid design to permit incorporation of selected clays in the fluid for rheology control and stabilization of the aphrons. In addition, the chemistry of the aphron membrane has been altered using a polymer/surfactant package so that the longevity and resistance to pressurization of the bubbles are greatly improved.

The authors will discuss the design and properties of the new Alternative aphron-based drilling fluid and how these characteristics can be used to advantage in a drilling operation.
Benchmark Performance: Zero Barite Sag and Significantly Reduced Downhole Losses with the Industry's First Clay-Free Synthetic-Based Fluid
Authors: Burrows Kim , Carbajal David , Kirsner Jeff , Owen Bobby
Published: December 2007

Proposal

Since the introduction of invert emulsion fluids in the 1960s, oil-based fluids (OBF) and synthetic-based fluids (SBF) have been formulated with a similar group of components: base oil, organophilic clay and lignite, lime, CaCl2 brine, and emulsifier. The family of invert emulsion fluids has remained closely related in terms of mud properties and performance expectations.

In 2001, an SBF formulated entirely without commercial clays or lignites was introduced in the Gulf of Mexico (GOM). Rheological properties are controlled through the emulsion characteristics, a radical departure from accepted solids suspension mechanisms. The behavior of this unique fluid has changed perceptions about what constitutes "good mud."

The clay-free, emulsion-based fluid (System) has consistently prevented detectable barite sag on 80+ wells drilled with it to date. Based on observed fluid densities after long static periods (an 8-day logging run in one case) and verified by modular dynamic test (MDT) log data on numerous high-angle wells, the fluid's unique emulsion structure and wetting characteristics prevent settling of barite and other solids.

Attempts to control barite sag with conventional clay-based SBFs have produced mixed results. A 14.0-lb/gal SBF treated with sag-prevention organophilic clay showed a 0.3-lb/gal density reduction in the initial return flow and a 0.3-lb/gal density increase in the tail flow after a 52-hr logging run. This 0.6-lb/gal variation in density was deemed "manageable." However, the treatment resulted in a 20% increase in the funnel viscosity at 75°F, demonstrating an adverse effect on the rheology after increasing the clay concentration by only 0.2 lb/bbl. At lower temperatures encountered at the sea floor, this effect would be amplified.

In addition to preventing barite sag, the System has provided other important field-documented performance advantages: Whole mud losses reduced by an average of 60% while drilling, running casing, and cementing (with 80% reductions reported on several deepwater wells).Significantly lower ECDs, validated by pressure-while-drilling (PWD) data.High, flat gel strengths that break with minimal initiation pressure, validated by PWD data.Highest standard of compliance with environmental regulations governing GOM operations.

The System is currently under consideration for use offshore West Africa, offshore Brazil, and the Asia-Pacific region.
Reformulating an Oil-Based Drilling Fluid with Especially Selected Chemicals Lead to Development of a Low-Viscosity High-Sag Stability Drilling Fluid
Authors: Taugbøl Knut , Sandberg Gerd Marit , Cullum Daryl , Dyrkolbotn Erik , Jacob Hans , Grevstad Kvaal
Published: December 2007

A conventional oil-based drilling fluid was determined not to be applicable for drilling narrow hole annuli in a mature field offshore Norway. Drilling these wells with a very narrow hydraulic window required an oil-based drilling fluid with reduced viscosity and improved sag stability.

A totally reformulated drilling fluid system was developed. The combination of base oil and selected products produced a fluid with a flatter rheological profile, resulting in reduced plastic viscosity (PV) and increased low shear rate viscosity (LSRV). This rheological profile reduced equivalent circulating density (ECD) and improved sag stability. This rheological profile also directly impacted pump pressure and hole cleaning capabilities, delivering lower pump pressure and allowing for higher pump rates and improved hole cleaning.

This paper presents the experimental work performed when developing the system for this specific application. The authors also will present field data and compare the performance of the new drilling fluid system with that of conventional systems.
Case Study of a 300-ft Water Depth Jackup in a Class IV Hurricane
Authors: Duhaney Harvey , Keys Harold , Daigle Paul , Laird John
Published: December 2007

This paper examines the ability of a Levingston Class 111-C jackup rig to withstand hurricane winds of 128 knots, which significantly exceeds the rig's 100-knot storm rating. It compares the analytical results of an engineering study focused on predicted rig attitude, areas of failure, and areas of high stress with the actual rig conditions observed.

Details of the shipyard repair show how an innovative chord repair method was used to dramatically decrease the cost of repairs and allow the rig to be returned to service in only 28 days.
Innovative Design for Deepwater Exploratory Wells
Authors: Cunha J. C.
Published: December 2007

Currently, in the southeastern cost of Brazil, a major deepwater exploratory campaign is being carried out. In a period of two years more than 150 wells are expected to be drilled. With water depth varying from 1,000 to 2,800 meters (3,280 to 9,200 ft), these exploratory wells are being designed and drilled taking into account three major points, safety, well data reliability and well cost.

On the design of the wells various innovations were implemented. Casing design is aimed to minimize the number of casing sections and a new improved deepwater wellhead system is being used. The drilling fluid system has been specially planned to improve borehole quality, cuttings transport and drilling efficiency.

The innovative approach adopted to drill the wells significantly reduced the total drilling time, which was very important due to the shortage of deepwater drilling vessels in the current market.
Ultrafast Drilling in the Gulf of Thailand: Putting Science into the Design Process
Authors: Pinto C. J. , Pendleton L. E. , Dick J. L. , Sinor L. A. , Oldham J. , Stauffer B.
Published: December 2007

A novel PDC bit design, the result of high end numerical modeling and laboratory testing set the Gulf of Thailand field record for rate of penetration during its first run by averaging 840 ft/hr over the 5,040 ft section. This was accomplished while building inclination from 26° up to 56° before dropping back to 37° at total depth. The bit also made the planned azimuth turn from 305° to 258°. The same design later pushed the performance record further by averaging 1,023 ft/hr over a 6,144 ft. section. Instantaneous rates in excess of 2,000 ft/hr were documented over a 1,000 ft section of this hole. Designing a bit that maximizes rate of penetration while maintaining a neutral walk tendency in rotate mode is presented in this paper.
Extending the Drilling Operating Window in Brent: Solutions for Infill Drilling in Depleting Reservoirs
Authors: Davison J. M. , Leaper R. , Cauley M. B. , Bennett B. , Mackenzie A. , Higgins C. J. , Shuttleworth N. , Wilkinson D.
Published: December 2007

The Brent field is located in the Viking Graben of the northern North Sea and produces from the Brent Formation and the deeper Statfjord Formation. Virgin reservoir datum pressure in 1976 was approximately 5,655 psi at 8,700 ft TVDSS. Pressure support was maintained until the 1998 since when reservoir pressure has been depleting at about 500 psi per year. The current datum pressure in the Brent units is approximately 1600-1700 psi.

Significant lost circulation problems started to be experienced in the late 90's and a study identified the cause as the narrowing of the mud weight window as reservoir depletion gradually lowered the fracture gradient [ref 1]. Mud weights have been lowered to mitigate against the costly lost circulation events. The mud weights currently used are typically 700-900 psi less than the shale pore pressure (i.e. underbalance). Two case histories from sub-horizontal wells last year illustrated that the shales can be drilled over 900 psi underbalanced with no indication of shale failure, however, when running in liners they both hung-up where shales had collapsed. Based on this experience, the minimum mud weight for drilling the sub-horizontal reservoir sections has been set at 700 psi underbalance relative to the interbedded shale pore pressure.

Reservoir depletion has reached the point where the (static) minimum mud weight for shale stability is almost equal to the fracture propagation pressure (FPP) for the reservoir sands. In the first half of 2002, 5 of the 7 wells drilled experienced lost circulation. The average losses volume per well was over 5,000 bbls with nearly 19,000 bbls being lost on one well. Of more significance is the NPT associated with the losses, this averaged over 300 hours per well. The average monetary cost of the lost time and mud volume was close to £1 MM per well. In an environment drilling low cost sidetracks, accessing reserves of 1-2 MM boe, this situation was unsustainable.

A task force set about finding possible solutions to combat the lost circulation problems. After technical review, including laboratory testing, a recommendation was made for a size and concentration of graphite to be added to the OBM. In 10 field trials to date all the sections reached TD without inducing lost circulation, however, 4 of the 10 sections did experience losses when running the liner and/or circulating prior to cementing. With the addition of the graphite the average losses per well has dropped from 5,238 bbls to 621 bbls and the associated NPT has dropped from 302 hours to less than 1 hour per well. Recent field data suggest that the graphite could add approximately 1000 psi to the fracture breakdown pressure. This opens a host of possibilities for future infill drilling in depleting reservoirs.