bluuebunny/crossref_metadata_2025_split huggingface dataset:
Tortuosity versus Micro-Tortuosity - Why Little Things Mean a Lot
Authors: Gaynor Tom M. , Chen David C-K. , Stuart Darren , Comeaux Blaine 
Published: December 2007

Abstract
Tortuosity is commonly defined as the amount by which the actual well bore deviates from the planned trajectory. Elimination of excessive tortuosity has been regarded as a critical success factor in extended reach drilling operations. In this paper the authors will refer to "micro-tortuosity", not measurable by survey data, in which the hole axis is a helix instead of a straight line. It is argued that this is Lubinski's "crooked hole" described in the early 1950's. The paper presents a study of micro-tortuosity using field data from hundreds of wells. The paper details how and why microtortuosity occurs and the negative impact micro-tortuosity can have on the entire drilling operation. The paper also presents a solution that eliminates or drastically reduces micro-tortuosity.
Field results will be presented to demonstrate that microtortuosity is in fact the dominant component of the total tortuosity.
Two-Phase Steady-State and Unsteady-State Relative Permeability Prediction Models
Authors: Ibrahim M. N. Mohamad , Koederitz L. F. 
Published: December 2007

Abstract
Laboratory measurement of relative permeability using either steady-state or unsteady-state methods can be expensive and time consuming. Each method has certain advantages, resulting in preferences of one particular method over the other. The primary advantage of the unsteady-state method is that it is faster than the steady-state method. This paper presents a Linear Regression Model approach for developing prediction equations for water-oil and gas-oil relative permeability from steady-state and unsteady-state experimental data. These equations offer an alternative technique in determining relative permeability values and provide a better statistical representation of relative permeability values for a reservoir as a whole since ample amounts of data were used in developing them. The data for this study were obtained from published literature of the Society of Petroleum Engineers and various industry sources. Equations were developed for water-oil and gas-oil systems based on formation type and wettability in addition to the methods of measurement. Only equations for sandstone formations are presented in this paper due to the lack of data available for other formations. The adjusted coefficient of multiple determination, R2adj is used as a criterion of a good prediction model in this study in addition to a residual plot. The equations developed in this study are easy to use: nine out of twelve developed equations require only one independent variable in order to generate a relative permeability curve, and consist of no more than seven terms in each equation. The prediction equations are compared with previously published correlations where possible and the plot of the prediction equations indicates that the unsteady-state method results in lower oil relative permeability values and higher water relative permeability values at a given saturation than the steady-state one.
Effectiveness of Intelligent Completions in a Multiwell Development Context
Authors: Yeten B. , Jalali Y. 
Published: December 2007

Abstract
We examine the behavior of a pair of matching horizontal wells, producing an oil column bound by a gas cap and an aquifer, to determine the impact of certain drilling and completion decisions on reservoir and production performance. We consider a well configuration that can be characterized as multiply parallel. The two wells are aligned in parallel fashion, are parallel to any two opposing no-flow boundaries (and equidistant from the other two) in a nearly square drainage area, and are in the same plane parallel to the initial gas-oil contact (GOC) and water-oil contact (WOC) planes. We examine the problems of well spacing, vertical placement, and directivity/orientation, in relation to instrumentation. Instrumentation, comprising downhole flow monitoring and control – when control is effectuated in an anticipatory mode – has an influence on the optimum placement between the initial fluid contacts, when optimum is defined in terms of cumulative recovery within a prescribed operational envelope. Operational envelope is defined by constraints on withdrawal rate, bottomhole pressure (BHP), gas/oil ratio (GOR), and forecast duration. Instrumentation of one well enhances also the performance of the adjacent well, and this effect is reinforced when both wells are instrumented. In the latter case, it is immaterial to recovery whether the wells are aligned in the same or opposing directions – introducing a degree of freedom for drilling/infrastructure planning -- and opposing directivity only partially compensates for lack of instrumentation in one or both wells. Stated results hold when each well is centrally located in its respective half-region, which is the spacing yielding the highest recovery; as spacing decreases the influence of instrumentation on vertical positioning weakens and its interchangeability with directivity strengthens. These results can be explained in terms of the limiting hypothesis of zero spacing, which is equivalent to a doubling of withdrawal rate for a single well. The latter increases the frictional losses in the wellbore, accentuates the coning problem, limits vertical maneuvering, and approaches the performance of two oppositely directed nearly coinciding wells—each producing at half-rate. The observation that the effectiveness of instrumentation depends on the severity of frictional losses in the horizontal conduit vis-a-vis the maximum drawdown at the sandface1 is thereby extended by the aforementioned friction-spacing interrelationship. Instrumentation is effective in the region bound by no coning and extreme coning; the latter being exemplified in this case by a virtual/ultimate doubling of withdrawal rate. The friction-drawdown interplay therefore provides a basis for screening candidates for instrumentation under the scenario of noncommingled production.
Cased Hole Formation Resistivity Tool Trial
Authors: Gyllensten Asbjorn , Boyd Austin 
Published: December 2007

Abstract
In the past hydrocarbon saturation have been monitored behind casing by pulsed neutron capture (PNC) logs. These tools have been quite successful in our environment onshore Abu Dhabi characterized by good porosity carbonate reservoirs with high salinity waters.
The ability to measure formation resistivity directly through casing in monitoring wells adds a new dimension, by allowing the measurement of water saturation further away from the borehole, less affected by the "damaged zone" invaded by mud filtrate and drilling fines. Until recently, resistivity logging in cased hole has been restricted to Induction logs in fiberglass lined wells. New advances in digital electronics has made it possible to produce the sufficiently accurate and stable downhole sensors required to measure formation resistivity through steel casing. The first Middle East trials of a new Cased Hole Formation Resistivity Tool (CHFR) took place in 1999/2000 in several ADCO wells.
Monitoring fluid saturation changes and movement in fluid contacts with time, including the identification of swept zones, barriers to flow and bypassed oil are the main applications for the CHFR. With a greater dynamic range than PNC-logs, the CHFR will complement data from sponge cores and open hole logs in swept zones, leading to more robust ROS determination.
The CHFR may also be used for primary evaluation, where no logs could be acquired in open hole, and allows re-examination of wells with old resistivity logs.
In low resistivity where the CHFR is near it’s specified limit of 1 Ohmm, the effects of resistive cement behind casing become important and require careful correction. PNC-logs are favored in this low resistivity range.
Field logs obtained in this trial will be presented and discussed in the paper.
Evaluating Uncertainty in Archie's Water Saturation Equation Parameters Determination Methods
Authors: Hamada G. M. , AL-Awad M. N. 
Published: December 2007

Abstract
Early in the life of reservoirs, it is required to estimate accurately hydrocarbon volumes in place. Modified Archie formula (Sw = (a Rw / φm Rt)1/n) is the basic equation to calculate water saturation. The exactness of water saturation value for given reservoir conditions depends on the accuracy of Archie parameters a, m and n. The terms of Archie relationship have been subjected to many laboratory investigations and even more speculation. There are many factors affect porosity exponent, m, saturation exponent, n and tortousity factor, a. Therefore, it is very difficult to fix Archie parameters regardless of reservoir characteristics; rock wettability, formation water salinity, permeability, porosity and fluids distribution.
This paper presents a new technique to determine Archie parameters a, m and n. The developed technique is based on the concept of three dimensional-regression (3D) plot of water saturation, formation resistivity and porosity. 3D method provides simultaneous values of Archie parameters. Also, 3D method overcomes the uncertainty problems due to the separate use of formation resistivity factor-porosity and water saturation equations to get a, m and n parameters.
Two field examples are given to show the applicability of 3D method and three other methods: 1) common values of Archie parameters, 2) conventional method and 3) core Archie parameter estimation (CAPE) method. The comparison between the four methods has shown that 3D method provides an accurate and physically meaningful way to get Archie parameters a, m and n for given core samples. Water saturation profiles, using Archie parameters deduced from the four methods, have been produced for the studied section in the wells. These profiles have shown a significant difference in water saturation values. This difference could be mainly attributed to the uncertainty level for Archie parameters from each method.
New Drilling System Brings Significant Improvements to Drilling Performance and Hole Quality in Middle-East Fields
Authors: Dahche Ali M. , Swick Stewart , Russell Richard 
Published: December 2007

Abstract
A unique combination of a matched, steerable, positive-displacement motor and a long gauge PDC bit has recently been introduced. The system was initially designed to address problems of high vibration which were known to be causing downhole tool failures. As the design elements of the system were developed it was realised that many of the problems being attributed to downhole vibration were related to hole quality issues such as borehole spiraling. A new system was designed to alleviate this problem. The new system, known as SlickBore TM, used a specially-designed steerable motor and a long gauge PDC bit that, together, retain the steerability of a conventional motor/bit system. SlickBore improved overall drilling efficiencies such as hole cleaning, excessive torque and drag, and poor ROP when sliding. Extensive field tests and subsequent commercial applications have clearly demonstrated the increased efficiencies of this system.
The majority of the initial runs with SlickBore were completed in clastic sequences in the North Sea, Gulf of Mexico, and Far East. When introduced to the Middle-East, the system’s performance in the predominantly carbonate sequences of the Arabian Gulf was unknown. Subsequent runs, however, have proved the system’s benefits also apply to these formations.
This paper will discuss the theories behind the design of the system and provide examples of the improved performance seen in the carbonate formations of Abu Dhabi.
New Application of Impregnated Diamond Bit on High Speed Motor: A Team Approach to Performance Improvement
Authors: Hendriks Peter , Tinkhof Rob , Hanouf Mohammed , Klink Zeinoun , Herran Guillermo 
Published: December 2007

Abstract
Recently, the design for deep wells in AFPC, Syria has been slimmed down in order to reduce well costs. This resulted in a general performance improvement. However, in the 6" reservoir section, which consists of hard and abrasive sandstones and shales in the Rutbah and Mulussa formations, performance deterioration was observed. These formations have traditionally been drilled with a combination of roller cone and PDC bits. In some fields, like the Shahel field, the ROP and bit life became unacceptably low.
To determine if this hard rock section could be drilled faster with alternative technology, the petrophysical logs were analyzed with a rock mechanics program to determine the formation's Unconfined Compressive Strength (UCS). The analysis also helped predict the formation's tendency to ball in addition to its abrasiveness and shale content. The rock mechanics program helped estimate how to drill the 6" section in the most efficient manner.
After comparing this analysis with the results obtained in a similar situations in the Saih Rawl and Barik fields in Oman, it was concluded that the use of high performance motors (1100 RPM) in combination with impregnated diamond bits had the potential to significantly reduce cost per meter. The analogy to Oman helped minimize the perceived risk of bit balling associated with drilling the Rutbah and Mulussa shale section in the Shahel field with impregnated technology. The combination of analytical study and comparison with offset data made it possible to justify a trial despite the high costs of running the high performance motor compared to the normal operating costs.
The new BHA and bit were used to drill the 6" hole section on well Shahel 111 between 3962 meters (m) and TD of the well at 4079m. The application was extremely successful saving in excess of US$150,000 and reducing the time to drill this section from 17 days to 3 days. ROP increased from 1.38 m/hr to 2.7 m/hr, while the number of bits used was reduced from nine to only one. All comparisons were made using a benchmark well in the same block of the field drilled less than a year before. Due to this breakthrough performance more complex wells, such as a level three multilateral, are now being planned for the near future.
Imaging Fluid Movements Through Sandstones, Sands and Model Glass-Bead Packs Using Fast NMR Imaging Techniques
Authors: Al-Mugheiry Mohammed Adil , Issa Bashar , Mansfield P. 
Published: December 2007

Abstract
Nuclear Magnetic Resonance (NMR) techniques are extremely powerful for characterising and quantifying the properties of the fluid-rock systems. Magnetic Resonance Imaging (MRI) has an additional attraction in that it can be used to generate image contrast through fluid transport properties.
The imaging experiments on such systems can be performed as static1 or dynamic2,3 fluid measurements. In some cases results of static-fluid measurements (eg. pore size distribution) are used to calculate a property that is more appropriately related to dynamic-fluid measurements (eg. permeability)
In this work, an efficient flow mapping technique called Pi-Echo-Planar-Imaging (π-EPI or Pi-EPI or PEPI) was used to quantify flow through different porous materials, ranging from model glass bead packs to unconsolidated sand specimens to consolidated sandstone samples.
The results presented demonstrate the potential of the highspeed snap-shot PEPI technique for quantitative spatial flow measurements in porous media.
The fluid flow studies on different porous samples seem to indicate a linear relation between the mean flow velocity and the velocity variance within a selected slice. A detailed simulation model for the interpretation of these results is described elsewhere4.
These results are still at the beginning of EPI applications in dynamic studies of porous media. Research protocols in this area are still at a relatively early stage and a far wider range of remaining challenges still exist5.
A Switch from Verticals to Dual Lateral Producers Accelerate Oil Production and Reduces UTC for Natih Field
Authors: Al Salhi M. , Al Maimani A. , Mäkel G. H. 
Published: December 2007

Abstract
The Natih field in Oman is a densely fractured carbonate reservoir with a STOIIP of 460 million m3. The displacement processes active in the Natih reservoir during the production period are very complex. Production started in 1967 with depletion of the reservoir resulting in production of oil from the fracture system and oil displacement by fluid expansion and solution gas drive. After these processes had ceased, gas oil gravity drainage in the secondary gas cap, water oil imbibition and water oil gravity drainage by aquifer below the secondary oil water contact continued to displace the oil from the matrix.
Based on field data available around the early seventies, it was decided in 1972 to arrest further pressure decline by water injection. In the 1980s, field performance reviews improved understanding of the displacement processes in the field and core analysis data pointed towards a relatively oil wet rock and a relatively large volume of production was ascribed to the GOGD process. Following this, further development of the field was wholly based on the drilling of GOGD producers in the oil rim and conversion to GOGD producer of suitably located wells.
Reservoir simulation work showed that substantial additional reserves could be developed by fracture oil rim lowering to a level close to the original OWC of the field. Through crestal gas injection and peripheral water production, coming from ESP wells placed around the field, this strategy was implemented. A further feature of this strategy is the drilling of multilateral wells with one leg close to the current oil rim and one leg in the anticipated final rim position. The upper leg produces oil, usually after a short "oiling-in" period. The lower leg initially produces water and helps lowering the rim.
This paper illustrates the reasons behind each stage of field development and reviews recent efforts to evaluate the effectiveness of the Natih oil rim lowering strategy and its future production potential through the use of 3D integrated modelling of Natih fracture system.
Looking to the Future - BP Amoco’s Gas-to-Market Outlook
Authors: McNeillie Graham 
Published: December 2007

Abstract
BP Amoco has a strategically important and new position in natural gas. Gas is abundant, inexpensive and clean but it is difficult to transport. The options for bringing gas to the market include pipeline, generating and transmitting electricity (gas by wire), LNG and Gas-to-Liquids (GTL). Transport by pipeline is the primary option for bringing gas to the market. Technology programs are underway to achieve significant pipeline cost reductions. If the end user of the energy requires electricity, then for a range of distances and energy levels it may be more economic to convert the gas into power and then transmit by wire using DC power systems. LNG is an option for delivering very large volumes of gas to markets far from the gas resources. Our latest gas marketing success story is the Atlantic LNG Plant in Trinidad and Tobago, which started up in 1999. Although the GTL option has had limited success, GTL projects are starting to look viable due to technology advances along with a low cost gas feed and a supportive fiscal regime.
Abatement of Water Production from Upper Permian Gas Wells in Saudi Arabia Using a New Polymer Treatment
Authors: Okasha T. M. , Nasr-El-Din H. A. , Al-Khudair W. S. 
Published: December 2007

Abstract
Excessive water production adversely affects the economics of gas wells and often leads to their premature shut-in. Production of high salinity water represents a major corrosion concern for casing, tubing, flow lines, and production facilities. Water production from gas wells can be significantly reduced by using water-soluble polymers or by blocking the flow of water using a suitable gel system.
A non-associate gas is being produced from the Upper Permian gas wells (Khuff carbonate gas reservoirs). Some of these wells produce large amount of very saline water (217 g/l). A chemical treatment is needed to reduce the amount of water produced.
An experimental study was conducted to screen various polymer solutions and gelling systems to treat gas-producing wells in the Khuff gas reservoirs. Experimental work included compatibility of two-water soluble polymers with Khuff reservoir brine, adsorption of these polymers on reservoir rocks, rheology of polymer solutions, injectivity and flow of these polymers into core plugs obtained from Khuff formation, at reservoir conditions.
The two polymers examined were compatible with Khuff reservoir brine under reservoir conditions. The amount of polymer adsorbed on reservoir rocks increased at higher polymer concentrations. Core flood tests showed that an organically cross-linked polyacrylamide-based polymer demonstrated the best performance for treating high permeability streaks where the gel treatment reduced the effective permeability to brine without affecting that to gas. Rheological measurements indicated that this gelling system could be placed into the target zone by bull heading or by using coiled tubing.
Modelling Water Breakthrough in a Fractured Carbonate Gas Reservoir
Authors: Weber Alexander , Brauckmann Franz , Rijkels Lex , Bourne Stephen J. 
Published: December 2007

Abstract
This paper describes a Permian evaporite carbonate gas field that has been plagued by severe water problems since it was put on production in the mid-80s. The field is a carbonate complex consisting of three communicating reservoirs that are heterogeneously fractured. Matrix permeability is typically less than 2 mD, except in one highly permeable streak, where it can be as high as 5 D. The permeability of the natural fracture network is extremely heterogeneous, and varies by up to a factor 100 over the field. Complex interaction between fractures, matrix and the highly permeable streak caused a surprising pattern of water breakthrough, which can be explained by a geomechanical model for the heterogeneous natural fracture network. This predictive, field-wide fracture model was validated and constrained by both geological and flow data.
First, the stress distribution around seismically visible faults was calculated assuming homogeneous, isotropic, linear elastic rock mechanical properties, and frictionless faults. Second, the calculated stress field was used to simulate the growth of discrete fracture networks, which were constrained by statistically comparing fracture orientation and connectivity with that derived from core, BHI, PLT, mud loss, and well test data. Finally, the fracture networks were upscaled dynamically to the grid of a dual-permeability simulator, enabling field-scale multi-phase reservoir simulation. The flow model obtained this way matched historical production data from all wells. It also explained the source of water breakthrough and the inflow profile seen on PLTs. Integrating seismic, borehole, well test and production data to constrain and validate such a field-wide model considerably reduced the uncertainty in the final predictions.
This integrated, predictive fracture model is presently used to investigate future field development scenarios. To this end, the model is coupled to a surface network simulator, which comprises the whole infrastructure. The fully coupled surface and subsurface models offer the flexibility to optimally plan the position and timing of new wells, the size of compressor units, additional in-field trunk lines and the gas offtake.