bluuebunny/crossref_metadata_2025 huggingface dataset:
Case History of Hydraulic Fracture Optimization in Tight Gas Wells with Water Production in the Wind River Basin, Wyoming
Authors: Dempsey Brett J. , Taki Hadir , Druyff James C.
Published: December 2007

The Cooper Reservoir is located in the north-eastern end of the Wind River Basin. Wells are completed in the lower Fort Union and Lance formations at true vertical depths from 3300 to 8200 ft. Fracture treatments are complicated by water producing sands interspersed among up to a dozen or more gas producing sands as well as mobile water within the gas producing zones. An extensive data set of core analysis, rock mechanics testing, pre- and post-fracture well logs, pressure build up analysis, detailed fracture modeling, and detailed production analysis was compiled on 56 completions in order to better understand and evaluate well performance and stimulation effectiveness in this field. The evaluation is based primarily on the use of the reciprocal productivity index (RPI) graphical production analysis method. RPI uses daily production and wellhead pressure data to determine the effectiveness of the treatments by several parameters including flow capacity (kh), reservoir flow geometry, drained volume (area), and effectiveness of produced liquids management. Significant variations in reservoir quality and completion effectiveness were observed.
Problems Calibrating Production and Seismic Data for Fractured Reservoirs
Authors: Brown R. L. , Gupta A. , Wiggins M.
Published: December 2007

The permeability and seismic properties of fractured reservoirs are not easily correlated. A part of the problem is that seismic properties are controlled by the elastic properties of the rock grains, the pore-space/crack-space geometry, the connectivity of the pore spaces and any local flow that occurs during the transmission of the seismic signal. Permeability, however, is governed by the pore-space geometry, the effective length and apertures of the cracks as well at the connectivity of the cracks. One way to calibrate the permeability and the seismic is to identify a "sweet spot" within a reservoir where certain simplified assumptions can be made regarding the fracture permeability. Under these ideal conditions, it is possible to correlate the seismic response and the production data using simplifying assumptions. After the calibration is accomplished at the well control, these results can then be used to predict the permeability variations away from the well control using the seismic response and models for the relationship between the permeability and the seismic properties. This approach requires the development of empirical relations between the seismic response and the permeability of the reservoir.
Case Study: A Step-Change and Continuous Improvement in Safety Performance
Authors: Meckert J. P. , Stephens M. E.
Published: December 2007

The contract drilling industry continues to injure too many people, especially U.S. Land. Industry's improvement has been slow, erratic and current accident rates remain high. U.S. Land contract drilling is most concerning, as this category of IADC's Accident Statistics Program consistently performs worst.

Drilling contractors must take responsibility, and establish their own standards for safety. Today, the contractor / operator relationship is governed by contracts containing "knock-for-knock" indemnities and independent contractor status, and widely varying degrees of both operator safety support and drilling contractor safety ownership. Also, government authorities, such as OSHA, mandate that employers provide a safe workplace. Drilling contractors cannot be dependent on operators, nor government authorities, to provide, impose and / or enforce safety standards.

In 1997, Nabors Drilling USA, Inc. ("NDUSA") made a commitment to create a step-change and continuous improvement in safety performance under the belief that all of its 5000 employees should return home without injury at the end of work. While NDUSA had historically performed better than industry peers, the company was not satisfied and thus established a framework, devoted the resources and set standards to achieve consistently challenging goals. During the subsequent three years, NDUSA and the industry experienced one of its most volatile and difficult operating periods in history.

Since October 1997, NDUSA has achieved an 80% reduction in LTA incidence rate, 70% reduction in recordable incidence rate, and avoided 655 employee injuries. If NDUSA is compared to IADC's U.S. Land overall rate in 1998 and 1999, NDUSA alone prevented 90 workers from experiencing lost-time accidents and 250 overall recordables.

From both a moral and economic standpoint, the effort is justified. If the whole U.S. Land industry had adopted such measures and achieved similar goals in 1998 and 1999, U.S. Land companies would have avoided a total of 445 (or 63% of) lost-time accidents and 1,225 (or 40% of) recordables.
Redefining the Environmental Envelope for Surface Bops on a Semi-Submersible Drilling Unit
Authors: Gallagher Kevin T. , Bond David F.
Published: December 2007

One of the primary drivers for the deepwater exploration is currently the rig size to be able to support a large heavy riser and subsea BOPs. This in turn limits rig availability, which significantly increases rig rates. Surface BOPs (surface stack) offer an opportunity to utilise much smaller semi-submersible rigs and prelaid moorings, provided the system could manage the environmental conditions.

Woodside Energy Limited has designed a surface BOP (SBOP) and high-pressure riser system to be used on semi submersible drilling units for exploration drilling in the harsh environment of the North West Shelf, in Western Australia. In order to comply with Safety Case legislation in Australia the process described in this paper included system analysis, risk assessment and detailed design.

The end result was a SBOP system with several unique features that allow operations in harsher operating environments than have previously been considered with this technology. These include novel slip joint design, BOP support configuration and a unique seabed arrangement. The seabed arrangement allows management of the environmental loads, ability to weight shed the casing loads and mechanically disconnect / re-connect. The ability to re-connect also permits the suspension and or conversion of the well from an exploration to a production well offering significant cost reduction potential for sub-sea completions.
A Novel Approach To Slim Well Delivery
Authors: Erivwo O. E. , Owoeye O. O. , Ogoke V. C.
Published: December 2007

With the need to maintain competitive advantage in a low and volatile price environment, a cost leadership initiative was proposed to slim down Imo River 66 (EX-SDTQ-2) to achieve a 25% reduction in capex without compromising its offtake potential. A novel approach was used in the 7-5/8" x 5-1/2" x 3-1/2" single skin well configuration with 3-1/2" expandable sand screens (ESS) deployed in the horizontal section. The ESS was expanded to 4-3/4" which maximised the completion liner size and minimised the drain hole annulus thereby enhancing effective reservoir management. This paper presents the conceptual design and planning of the slim well. It also focuses on the critical issues and key challenges that were addressed to successfully drill the well and deploy the ESS.

The success of Imo River 66 resulted in a savings of 2.3 million dollars (32% cost reduction). The well proposed with a potential of 3000 bopd has already been tested to a post clean up potential of 3106 bopd at a lower bean size. This success has provided opportunities for step change reduction in construction costs of future wells with similar potential. It has also opened up new vistas in development options for brown fields and further optimisation opportunities in well design.
Fracture Gradients in Depleted Reservoirs - Drilling Wells in Late Reservoir Life
Authors: Alberty M. W. , McLean M. R.
Published: December 2007

A key requirement to successful drilling is the selection of a mud weight that provides sufficient pressure to prevent the influx of formation pore fluids, while at the same time not exceeding the fracturing resistance of formations exposed in open hole. The correct prediction of how pore pressure and fracture resistance varies through the intervals to be drilled is critical to designing an appropriate casing program.

In many instances fracture gradient profiles will be well defined from experiences of drilling offset wells. However, in cases where casing programs are modified or sub-subsurface conditions have altered, for example as a result of pressure depletion, predictive methods are required to extrapolate the previous measurements and inferences of the fracture gradient. Conventional wisdom on fracture gradients suggests that pressure depletion can significantly reduce fracture resistance and seriously increase drilling difficulty. However, an alternative theory on fracture gradients, coupled with growing evidence of its applicability, indicates that sands are not in general the cause of losses associated with induced fractures. Despite sands often being under lower in situ stress than adjacent shale layers, it is in fact the shale that are more likely to host an induced fracture responsible for large-scale mud losses. In general, shale has a higher Poisson's ratio than sands. In addition, the extent of pressure depletion will be less in intra-reservoir shale than in the sand layers. Therefore, the predicted effect of reservoir depletion on the fracture gradient is much less if based on the shale intervals than if based on the sands.

Here the theories on fracture gradients and the reasons for their differences are discussed. Field examples supporting the more optimistic approach are presented.
How to Diagnose Drilling Induced Fractures in Wells Drilled with Oil-Based Muds with Real-Time Resistivity and Pressure Measurements
Authors: Bratton T. R. , Rezmer-Cooper I. M. , Desroches J. , Gille Y-E. , Li Q. , McFayden M.
Published: December 2007

Major problems are often encountered in relaxed basins when extended reach wells are drilled through depleted reservoirs. As wellbore inclination increases, the imbalance between vertical and horizontal stresses can cause formation breakouts leading to increased cuttings and increasing the potential for stuck pipe. Higher mud densities can stabilize the imbalance and facilitate cuttings transport, but increase the risk of differential sticking and lost circulation. Additionally, higher mud densities can create fractures that take mud while drilling and return mud during connections. This ‘ballooning’ or ‘weeping’ complicates the correct diagnosis and increases the risk of losing the well. Early identification of these competing mechanisms can be critical to successful drilling.

Real-time resistivity-at-the-bit images are now possible to aid diagnosis, but are currently limited to water-based muds, and a limited range of conductive oil-based muds (OBMs). Nevertheless, conventional resistivity measurements can still be used in wells drilled with OBM. A case study is described of a highly deviated Gulf Coast well drilled with synthetic OBM that penetrated a severely depleted reservoir. Based on the data collected the original assumption that depleted sands were the only source of lost return zones was in error. The losses were found to be in the bounding shales as well. After losing two wellbores, the project was abandoned due to wellbore instabilities and limited reserves.

Investigations into the lessons learnt highlight how multiple passes with both resistivity and annular pressure measurements could have been used to diagnose the location and mechanism of borehole failure, and hence suggest appropriate action. Indeed, the resistivity measurements were found to be responding to induced fractures hours before any changes in equivalent circulating density (ECD) or significant drilling observation.

A methodology is given for diagnosing drilling induced fractures from the real-time measurements, so that remedial actions can be promptly taken. Success in future operations will come from including these new methods into the drilling plan.
Successfully Drilling Highly Depleted Sands
Authors: Shaughnessy John , Fuqua Ron , Romo Louis
Published: December 2007

BP has successfully drilled with up to 13,000 psi differential pressure through a depleted sand in a South Louisiana well. Close attention to operational procedures avoided stuck pipe and unmanageable mud losses. Bit selection and performance, BHA design along with mud system, cement program and casing design will be reviewed. Total costs were reduced by avoiding downtime associated with the high differential and by managing the sand without increasing casing sizes.
Drilling with Aerated Fluid from a Floating Unit. Part 1: Planning, Equipment, Tests, and Rig Modifications
Authors: Santos Helio , Rosa Fabio , Leuchtenberg Christian
Published: December 2007

Underbalanced Drilling (UBD) can be compared today with the horizontal drilling technology 15 years ago. Most probably, the majority of the wells will be drilled underbalanced in the near future. While onshore and offshore operations from fixed platforms have been conducted, UBD from floating units is still a challenge. With the majority of its hydrocarbon reserves located in deepwater, Petrobras decided to start a project to develop technology to drill wells with light-weight drilling fluid from a floating platform. This technology is seen today as the first step to reach UBD from a floating vessel, including deepwater locations. The present paper describes the steps taken so far to develop all the new equipment required and the HazOp meetings to discuss and approve the technical details and procedures. The paper also discusses the difficulties encountered during the negotiations with a rig contractor, to allow and fully understand the operation on board of one of its platforms. The paper finally discusses the best options from the lessons learned so far to have rigs ready to use this technology in the near future.
Determination of Borehole Quality, Diameter and BHA Directional Response: Eccentric Tool Test Program for Expandable Casing Application North Sea
Authors: Lodder Robert Jan , Ruggier Michael , Sinor Allen , Bobrosky Douglas , Radford Steve
Published: December 2007

A detailed test program was performed with an eccentric tool at the Baker Hughes Experimental Test Area (BETA) field research facility to evaluate the feasibility of its use in an Expandable Tubular Technology application in the North Sea. The testing used a 9–7/8" Drill Out Steerable Ream While Drilling (DOSRWD) tool in conjunction with 6–1/2" pilot bits (both PDC and roller cone). Motor bent housing settings included 1.0°, 1.5°, 1.75° and 2.0° bends to evaluate directional and stability response. Surface speeds were varied from 0, 35, 50 and 75 rpm at each motor housing setting. Caliper logs including four and six-arm and ultrasonic borehole imaging (UBI) tools were used to characterize the borehole under all conditions. The analysis included directional tendencies, down hole vibration monitoring and borehole diameter, quality and degradation over time. The test results show the 9–7/8" DOSRWD system is capable of providing the high quality wellbore required for expandable tubular technology, ensuring the casing can be run, expanded and isolated across the formation.
Erskine Field HPHT Workover and Tubing Corrosion Failure Investigation
Authors: Mowat D. E. , Edgerton M. C. , Wade E. H. R.
Published: December 2007

The first workover of a UK North Sea ‘high pressure high temperature’ (HPHT) production well was successfully completed in August 1999. The workover in Texaco’s Erskine field resulted from failure of the duplex stainless steel production tubing in the through water zone. The workover benefited from detailed planning and peer reviews to identify necessary contingencies and technologies.

The tubing failure investigation is summarised. The failure was attributed to external chloride stress corrosion cracking in the calcium chloride packer fluid resulting from air ingress to the annulus.
Managing Drilling Knowledge for Improved Efficiency and Reduced Operational Risk
Authors: Bargach Saad , Martin Charles A. , Smith Reid G.
Published: December 2007

Drilling techniques and technology are changing rapidly as the industry continues to innovate in well construction. To keep pace with these advances, training must take a new direction, so that personnel are able to take advantage of new measurements and techniques in real time to improve drilling efficiency and reduce operational risk. In this dynamic and demanding environment, it is imperative that a drilling services organization improve its knowledge management— the ability to capture, share, and apply worldwide expertise— to consistently supply the best drilling solutions and practices. This is fundamental to achieving the vision of fully automated drilling systems operated remotely from the town office by a distributed, multidisciplinary team of experts.

Schlumberger started a knowledge management pilot project in early 1999. The initial focus was to build a Knowledge Hub—a Web portal for drilling personnel. Key sections are devoted to best practices and lessons learned. Practices are submitted by field engineers, validated by experts, captured in the knowledge base, and pushed to field crews for use worldwide. Today the ability to use in one part of the world what we have discovered in another is made possible by information technology tools and techniques. However, people are both the key to successful knowledge management and its most challenging element. Success depends on motivating people to share their knowledge and reuse that of others as part of their day-to-day jobs.

This paper describes the steps taken and the lessons learned along the way in establishing and institutionalizing knowledge management for Anadrill. It describes best-practice programs from companies inside and outside the petroleum industry and explains the program that was adopted.
Variations in Formation Temperature Due to Mature Field Production Impacts Drilling Performance
Authors: Sathuvalli U. B. , Suryanarayana P. V. , Erpelding P.
Published: December 2007

Optimization of offshore production facilities requires the placement of several wellbores in close proximity of each other. If the wells are spaced sufficiently close, diffusion of thermal energy between the wellbores has a pronounced effect on the undisturbed geothermal gradient of the formation. Such variations of the geothermal gradient have been observed while drilling new wells in mature offshore fields with wells that have been in production for six months or longer. When a new well is drilled in this section of the formation, higher geothermal temperatures are encountered at shallower depths. This can seriously impact the drilling, mud, cementing and casing programs.

Previous research concerning the heat transfer analysis of injection, production, and circulation is based on the thermal interaction of a single wellbore with the formation. These works typically use axisymmetric finite difference formulations of the wellbore heat transfer equations. Unfortunately, this approach is not adequate to analyze the effects of multiple wellbores. This paper bridges this gap with a technique to evaluate the thermal proximity effects of multiple wellbores. The method is based on the integral formulation of the heat conduction equation and it demonstrates the alteration of the undisturbed formation temperature profile. The results suggest that local geothermal temperatures in the vicinity of a producing field can be increased by several tens of degrees Fahrenheit.
A Pragmatic Approach to Injection Management of a Large Water Flood in The Largest Oil Field in Oman
Authors: Al-Mugheiry Mohammed Adil , Al-Barwany Amour , Al-Abry Yaaqub , Lozano Jose , Al-Lawati Mohammed
Published: December 2007

The Yibal Oil Field in the Shuaiba Formation in North Oman is the largest oil filed in Oman, contributing about 15% of the country’s production. The heavily faulted and fractured 70 km2 carbonate anticlinal structure was brought on stream in 1969 initially under depletion drive. This was followed by oil-leg injection directly into the oil column in 1972, then later by acquifer injection in 1980. Since then, more vertical infill drilling was carried out and almost all oil-leg injectors were converted to acquifer injectors with additional new injectors.

The associated oil-gain is found empirically to be about 10% to 15% of the injected water (typically, 1000 m3/d injected water can result in about 120 m3/d oil gain). However, the injected water volumes varies substantially from injector to injector through out the field, giving rise to uneven water injection distribution which ranges from 50 m3/d on the low side to about 4500 m3/d on the high side. Furthermore, the subsurface water movement exhibit various mechanisms such as bottom water rise, bottom water coning, fault plane channeling, fault plane line drive, radial flooding, fingering and edge water encroachment.

The intense horizontal drilling campaign in 1993 and improved higher off-take horizontal producers after simulation studies in 1997 resulted in direct impact on localised pressure drop and early water break-through. In addition, injected water was seen to have direct impact on the performance of some producers but not others combined with the difficulty of optimising the injectivity in some low-pressure areas due to surface or subsurface constraints. Thus, the need to develop a more pragmatic approach is innevitable.

This paper discusses the development of injection management methodology of the very wide Yibal Water flood. In particular, the discussion focuses on the improvements in the water injection scheme to sustain the field with more than 300 producing wells (horizontal and vertical) coupled with intense drilling campaign (about 50 wells per year) in the last four years. The paper will address the in-house developed tools in addition to the associated voidage and pressure mapping to manage the oil displacement in this complicated mature field. With the aid of these tools, areas with anomalies in the static pressure and voidage maps are identified and stability is re-established through combined off-take control, water shut-off, closing high water-cut or gas-oil-ratio wells, converting watered-out producers to injectors, optimising existing injectors or drilling new injectors.
Calibration of Permeability Derived from NMR Logs in Carbonate Reservoirs
Authors: Amabeoku Maclean O. , Funk James J. , Al-Dossary Saleh M. , Al-Ali Hussein A.
Published: December 2007

This paper discusses the calibration of nuclear magnetic resonance (NMR) logs to determine permeability distribution in carbonate reservoirs. The examples presented indicate the need for rigorous and integrated calibration to succeed in permeability estimation.

The promise of the NMR logging tool to deliver, among others, mineralogy independent total porosity and permeability makes it a tool of choice in formation evaluation. Significant savings in coring costs, particularly in horizontal wells, are possible with the NMR tool.

In sandstone reservoirs, NMR has worked remarkably well in the estimation of porosity, irreducible water saturation, producible fluids, and permeability. But the success rate is low in carbonate reservoirs, with respect to permeability. This can be attributed to the complexity of carbonate reservoirs and the lack of proper calibration of the logs with laboratory data or some measured reference.

The paper discusses calibration of NMR logs for permeability estimation, using laboratory NMR measurements, routine core permeability data, and formation test data. The calibrated models are then used to re-compute permeabilities in the logged intervals. The examples illustrate that reliable field-specific permeability modeling is possible when all relevant data are integrated into the calibration effort. The calibration effort also shows that it is not sufficient to adjust only the pre-factors in the SDR and Timur-Coates’ permeability models in order to make the NMR log data match the core data. The porosity exponent (m) and T2LM (or FFI/BVI) exponent (n) also require adjustments. The default values of m=4 and n=2 did not apply in most of the cases examined in this paper.
Case Study: Development of a Comprehensive Simulation Model for a Large Middle Eastern Carbonate in Kuwait and the Partitioned Neutral Zone, Kuwait
Authors: Sherman B. Blake , Al-Jadi Mohammad , Al-Najdi Ali , Al-Maraghi Easa , Nair C. V. G.
Published: December 2007

A reservoir management tool has been developed through the application of the latest in reservoir simulation technology for the Umm Gudair field - a large carbonate reservoir which is located in Kuwait and the Partitioned Neutral Zone. This paper will highlight the critical steps which were required for the development of an effective reservoir management tool for the field, such as maintaining the integrity of the geologic model through effective upscaling, thorough analysis of the engineering data, and the integration of the engineering data into the simulation model.

A complex geostatistical geologic model was built by a team of geoscientists using the latest in geoscience software and techniques. Because this geologic model was very detailed (144 layers, 10,000,000 cells), it was necessary to convert the geologic model into a reasonably sized simulation model through an upscaling process. In order to maintain the integrity of the fine-scale geologic model in a vertically upscaled simulation model, the engineering team applied flux-based upscaling techniques. These techniques allowed an appreciation for the effects of upscaling on the fluid flow, and generated a vertically upscaled model that effectively replicated the fine-scale fluid flow behavior. Two simulation models were generated - a coarse model containing 140,000 cells (to accelerate the history match process) and a 540,000 cell fine-scale model. The fine-scale model allowed for sufficient gridding detail for subsequent infill drilling studies. This paper discusses the efforts applied towards effectively converting the detailed geologic model to a simulation model through upscaling, capturing the engineering data in the simulation model, and the systematic approach applied in generating the history match. Finally, an overview of the quality of history match will be presented.
A Unique Approach to Enhancing Production from Depleted, Highly Laminated Sand Reservoirs Using a Combined Propellant/Perforating Technique
Authors: El-Bermawy H. , El-Assal H.
Published: December 2007

The primary objective in the design of a perforating program is to remove or minimize any impedance to the desired fluid movement from the reservoir to the cased wellbore. The possible damage that could occur from drilling-fluid contacting the formation is one of the significant problems that must be addressed in selecting the perforation technique. As drilling fluid enters the formation, it can deposit solid matter, cause clay swelling, and induce chemical precipitation, creating a damaged zone area around the wellbore. All of these resulting phenomena reduce the size of the pores available for fluid flow. In addition to the induced drilling fluid damage, the radial displacement of formation materials during the perforating event causes crushing and compacting of the area that immediately surrounds the perforation (better known as the crushed zone area), which will subsequently result in a reduced permeability envelope around the perforating tunnels.

Perforating the well in an underbalanced condition using super deep penetrating "premium" charges has proven to be an effective technique in removing near wellbore damage, as it allows the formation pressure to remove the damaged rock instantly. However, if the formation pressure is too low to move the damaged rock, permeability at the face of the perforation can be greatly reduced. In many wells, the damage can be so severe that only 25 percent of the perforations will produce.

This paper reviews the successful application of a combined propellant and perforating technique in depleted, highly laminated sand reservoirs. In the case histories discussed, applying this technique resulted in stimulated wellbore conditions that improved flow efficiency. The results from the pressure transient analysis are included and will verify the attained productivity improvements.

The paper also discusses the initial operational problems encountered in implementation of the propellant/perforating technique and the precautionary methods that were taken to address these scenarios.
A Multi-Purpose Reservoir Characterization Model
Authors: Shedid Shedid A.
Published: December 2007

The ultimate goal of petroleum engineering science is to maximize oil recovery at a minimum cost. This goal can be achieved by better understanding the heterogeneous nature of the reservoir rock. Reservoir characterization is considered the key to optimum oil exploration and exploitation.

The major goal of this research is to develop a multi-purpose reservoir characterization model capable of producing an effective reservoir description as well as an economical reservoir characterization. This model is developed to achieve the following purposes: (1) reservoir description of clean and shaly heterogeneous reservoirs using laboratory and/or in-situ (porosity and permeability) measurements, (2) robust and economical reservoir characterization of reservoir rock by using the concept of reservoir quality index in combination with various stress conditions during the extended life of an oil reservoir, and (3) investigate the effect of oil production (or stress) on reservoir characterization of clean and/or shaly heterogeneous reservoirs.

The newly proposed multi-purpose model incorporates petrophysical (porosity, permeability, and reservoir quality index), mechanical (effective stress, pore pressure, and average pore compressibility) properties and mechanics of fluid flow through porous media. Multiple cases are included to validate and illustrate the applications of the model in various situations considering different conditions of reservoir rock.
NMR Permeability Calibration Using a Non-Parametric Algorithm and Data from a Formation in Central Arabia
Authors: Al-Ajmi Fahad A. , Holditch Stephen A.
Published: December 2007

Nuclear Magnetic Resonance (NMR) logging provides a wealth of information to assist in the evaluation of a formation. NMR logs respond to the fluids in the pore space, and can be used to estimate lithology-independent values of effective porosity, pore-size distribution, bound and movable fluid saturation, and permeability on a foot by-foot basis.

Permeability models that include pore size distribution information are normally more accurate than models based on porosity information alone. Algorithms for estimating permeability from NMR measurements are based on the estimation of either a critical pore size or reducible water saturation. The algorithms that are based on empirical relationships will identify trends in permeability. However, to assure accuracy, the values of NMR permeability have to be calibrated with permeability data measured from cores. The typical NMR measurement is primarily sensitive to pore bodies, and is less sensitive to the size of pore throats that control permeability. Therefore, NMR calibration with core data is required for reconciling permeability from these two sources.

In this paper, optimal non-parametric transformation of variables with the Alternating Conditional Expectations (ACE) algorithm was used to calibrate NMR permeability to core permeability for a sandstone reservoir in Central Arabia. The use of the ACE algorithm significantly improved the correlation between the NMR and core permeability. Calibration of NMR permeability has improved the accuracy of the estimation of formation permeability using the NMR log. The permeability estimated using calibrated NMR esponse is positively correlated with core permeability with a correlation coefficient of 0.87.

Neural networks were also used to generate synthetic nuclear magnetic resonance effective porosity and permeability. A back-propagation neural network was used to associate and predict the relationship between conventional openhole logs, NMR permeability, and NMR effective porosity in control wells that have both NMR log and conventional openhole logs. The trained neural network was then used to generate synthetic NMR permeability and effective porosity to extend NMR curves to cover un-logged intervals and zones where borehole washouts affect the logging data. In addition, synthetic NMR porosity and permeability was generated for wells with no NMR logs. A Neural Network successfully predicted the NMR log response that would have occurred if NMR logs had been run, and created reliable synthetic NMR porosity and permeability.

NMR log porosity was compared eith porosity values from core, and calculated values of porosity from density log, neutron log, and sonic log data.
Stochastic Modeling of Porosity Distribution in a Multi-Zonal Carbonate Reservoir
Authors: Sahin A. , Al-Salem A. A.
Published: December 2007

Petrophysical variables, such as porosity and permeability in reservoir rocks, result from complex geological processes, and are characterized by considerable amounts of heterogeneity in their spatial distribution. The challenging task for geologists and engineers is to represent such heterogeneity in numerical reservoir models for flow simulation, leading to better predictions of reservoir performance.

Stochastic simulation techniques have commonly been adopted to construct numerical reservoir models in recent years. These techniques provide a range of equi-probable images or realizations of variable under consideration with a realistic level of heterogeneity. The Sequential Gaussian Simulation (SGS) is one of the popular conditional simulation techniques employed in reservoir characterization. The SGS algorithm provides a simulated value at any location by first determining the probability distribution at that location, and then drawing a number at random from this distribution.

The SGS technique was adopted to generate a three-dimensional, high-resolution reservoir model of porosity within the Upper Jurassic multi-zonal Arab-D carbonate reservoir in the Harmaliyah oil field, located in the Eastern Province of Saudi Arabia. The study was based on the well-log derived porosity measurements from 44 vertical wells. The generated models display the general pattern of the porosity distribution within the reservoir and provide the basic input for the flow simulation. As expected, the simulation model appears to have reproduced a realistic level of heterogeneity. Comparison of the histogram and statistical parameters of the input data with those of the simulated values reveals a close match in both the distribution patterns and the parameters.
A Unique Rigless Casing Leak Repair, Ghawar Field, Saudi Arabia
Authors: Styler James W. , Al-Suwailem Suliman S. , Akhnoukh Ramez L. , Leighton James R.
Published: December 2007

This paper describes the successful field application of a relatively new rigless technique to repair a casing leak in a saltwater disposal well in the Ghawar field in Saudi Arabia, the first installation of its kind in the Middle East. This unique repair method utilizes an electric-line-conveyed, non-metallic, composite sleeve composed of elastomers and thermo-setting resins reinforced with fibers. A description of the technology is presented, along with a brief history of its development, characteristics of the patch, and the installation procedure. The candidate selection process, candidate well history, and installation procedure for two patches are discussed, and economics are shown illustrating that this type of repair was economically superior to a rig workover.
A New Concept to Predict Sand Production from Extended Reach and Horizontal Wells
Authors: El-Sayed Abdel-Alim H. , Alsughayer Ali A.
Published: December 2007

The technology of extended reach and horizontal wells has recently progressed significantly. These wells have very few cost effective choices like slotted liners and openhole completion methods. Hole instability and sand production are the main problems of these completion techniques. To predict sand production an elastic plastic spherical cavity or cylindrical symmetry is assumed. Also, Mohr-Coulomb criterion is proposed for bore hole failure solution. These methods have limited applications and need actual cores to measure shear failure properties of rocks.

This paper introduces developed equations to predict sand production from extended reach and horizontal wells. A combination of Mohr Coulomb criterion and Von Mises criterion for cylindrical symmetry is developed and proposed to determine the hole instability and sand production. These equations allow calculating the sand free production rate for extended reach and horizontal wells depending on the uniaxial compressive strength of the rock. They also allow evaluating the effect of inclination angle, azimuth angle, well length and values and directions of in-situ stresses. Also, the equations can be applied easily in any area.
Means to Guard Environment from Pollutants & Hazards, a Tailored Risk Assessment Scheme to Control Failures of Hydrocarbons-Transfer Pipelines
Authors: Kandil Mohamed Essam , Anwar Wael Mohamed
Published: December 2007

Hydrocarbon transfer pipelines that passing/traversing across protected areas have always the risk of sudden failure due to unseen internal corrosion that may cause damage to the surrounding environment. Therefore, it is necessary to maintain the integrity of hydrocarbon transfer pipelines especially, aged pipelines in order to minimize the risk of its failures, avoid oil spill, protect the environment from pollutants and achieve a proactive pipeline failure control.

In general, internal corrosion could be attributed to the increased water content in operations, the decreased flow velocity, CO2 corrosion, under-deposit corrosion or microbiologically influenced corrosion (MIC). Therefore, in order to minimize/avoid MIC in pipelines, it will be necessary to apply a corrosion management program in order to preserve and assure the integrity and serviceability of pipelines.

This paper presents a pipeline risk assessment program that was designed to manage corrosion, control pipeline’s failures and to assure a renovated pipeline system. This program includes practical techniques to 1) refurbish a doubtful pipeline, 2) determine exact condition & remaining life of a pipeline and 3) to make active pipeline maintenance. This technique is successfully implemented in GUPCO Oil Company and proved its capability to be a powerful tool to evaluate & maintain the overall integrity/strength of GUPCO pipelines network. It is simple now for pipeline operators to identify areas of greatest impact to the environment & safety and to respond with the necessary course of actions to remedy the deficiencies. Thus, they succeeded in maximizing economic returns for GUPCO shareholders, protecting the safety of employees/community, minimizing risk to the environment and finally complying with the laws and regulations of Egypt.
A Successful Project of Progressive Exploration and Development for Shallow Gas Reservoir in Chenjiazhuang Arch
Authors: Sheng Ruyan , Cao Zhongxiang , Xiang Xiyong
Published: December 2007

Aimed at the characteristic that gas-bearing formation of shallow gas reservoir (SGR) shows bright spot on seismic cross-section, integrative technology research combining exploration and development has been developing in Shengli Oil Fields. After several years’ practice, a series of techniques of progressive exploration and development with high benefit for SGR have been created. Studies and practice prove that bright spot on conventional seismic section has nature of multi-solution, i.e. some kinds of reservoirs, such as lithologic reservoir, hydrogenous sandstone, gas bearing hydrogenous sandstone and gas bearing sandstone, all show the characteristic of bright spot. In order to solve this problem, special purpose processing involving 3D, G-log and amplitude versus offset (AVO) is used to distinguish between real bright spots and false ones. Four gas-bearing regions including Yanjia, Chenjiazhuang, Gunan and Sanhecun have been discovered and put into production since 1988. 162 probable bright spots have been found, and 60 new wells drilled with 56 successful wells. Drilling success ratio advances from 55% to 93.3%. Incremental proven gas bearing area is 48.2 km2 with gas initially in place 4.304×10 9m3, and gas rate is 375× 103m3/d. The spread application for this technology has been seeing considerable economic benefit, and it provides practical experience for exploiting such kind of reservoirs also.

Progressive exploration and development utilizing technology of seismic bright spot accelerates the step of getting production. Four steps, including special purpose processing and seismic data interpretation, programming development plan and fulfilling drilling and gas lines construction, gaining gas productivity and submitting proven reserves, are all accomplished in the same year. This paper introduces a typical example for the course of progressive exploration and development in Chenjiazhuang Arch.
Modeling a Rich Gas Condensate Reservoir with Composition Grading and Faults
Authors: Liu J. S. , Wilkins J. R. , Al-Qahtani M. Y. , Al-Awami A. A.
Published: December 2007

The Hawiyah Jauf Reservoir is a complex structural-stratigraphic trap located along the east flank of the uplifted Ghawar structure. The two important aspects of this reservoir are fieldwide composition variation and reservoir compartmentalization. The reservoir fluid samples obtained during developmental drilling show remarkable differences in fluid properties and condensate yields. The condensate yield of collected samples varies form more than 250 STB/MMscf to less than 100 STB/MMscf, and the reservoir fluid at the gas-water contact exhibits the near-critical behavior. Furthermore, the complicated fault system subdivides reservoir into several major compartments.

In order to model the fieldwide composition variation, all fluid samples must be characterized reasonably well by using one equation of state (EOS) fluid model. An eight-component EOS fluid model has been generated based on four fluid samples. A geological model was built to honor the faults that were interpreted from the recent 3D seismic survey.

A series of prediction runs are planned to forecast the reservoir behavior and hydrocarbon recoveries under various operational scenarios including simple depletion as well as cycling at different stages of production. Sensitivity runs are also made to investigate the impact of uncertainties associated with geologic and reservoir properties.
Pore Pressure Prediction Data Using Seismic Velocities and Log Data in the Offshore Nile Delta, Egypt
Authors: Badri M. A. , Sayers C. , Hussein R. A. , Graziano A.
Published: December 2007

One of the main challenges in the deep water of the offshore Nile Delta is the ability to predict pore pressure. In this difficult environment the rig cost and risk is high requiring an accurate estimate of pore pressure for safety concern, optimizing mud weights, and casing program. Pore pressure prediction has been based in the past on after drilling results and recently while drilling using log data such as resistivity and sonic measurements. Pre-drill pore pressure estimation has been obtained from transform models using seismic interval velocities. However, the accuracy of this estimate of pore pressure is directly related to the reliability of these interval velocities and the assumptions underlying the various pore-pressure models used. The availability of the 3-D velocity data from 3-D seismic surveys can provide valuable information that can be used to produce 3-D pore pressure cube.

In this paper, a feasibility study has been carried out on exploration wells in the offshore Nile Delta, Egypt, to estimate pore pressure using borehole seismic velocities. Two examples of highly pressured and normally pressured formations in the offshore Nile Delta will be presented. The first well had an unexpectedly high-pressure gradient (15.4 ppg, 1850 kg/m3) in the Pliocene formation section at depth less than 2000 m, resulting in a significant increase in the mud weight, and a well 28 days above the AFE. The second well was drilled based on similar mud weight properties as the first well but resulted in severe losses and well 15 days above the AFE. A velocity-pore pressure transform has been derived and results were applied on 2D seismic section.

The ability to predict pore pressure before drilling from 3D seismic velocities provides valuable information to optimize drilling strategy and significantly reduce well cost in deep water environment.
Efficient Technology Application to Optimize Deep Gas Well Completions in the Khuff and Jauf Formations Requiring Hydraulic Fracturing in Saudi Arabia
Authors: Solares J. Ricardo
Published: December 2007

The first phase of an accelerated project to develop Saudi Arabia's deep gas potential has been sanctioned, and a large number of new gas producers are currently being drilled and completed. A number of wells have been either acid or hydraulically frac’d, and preliminary production tests have shown significant productivity increases resulting from this type of stimulation. Consequently, plans have been finalized to frac most existing and future wells in this development.

Fracture initiation pressures average 16,000 psi. at downhole conditions, and H2S has been found present in several of the formations, so well completions capable of withstanding such conditions are of critical importance. This paper describes how the acquisition of WellCat™, Landmark's tubing stress analysis software program, and rigorous scrutiny of well completion components helped Saudi Aramco identify a significant number of mechanical weak links previously overlooked by an in-house computer program. The ability to analyze well completions in intricate detail, and model each frac stage with realistic fluid rheology, provided a powerful tool which helped identify weak links in need of removal to prevent potential problems.

A systematic approach to evaluate existing and planned well completions was implemented, close cooperation between several Saudi Aramco groups and Landmark established, specific modification recommendations issued, and an action plan to improve future completions and strengthen existing ones was put in motion.