bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Novel Coiled-Tubing Wall Thickness and Ovality Measuring Tool for Field Use
Authors: Standen Robert , Pike Don 
Published: December 2007

Abstract
Some clients of coiled tubing service companies increasingly demand inspection of the tubing immediately prior to or during field operations. There is a lack of suitable available equipment for inspection of tubing for wall thickness and ovality deficiencies, particularly where operation in potentially explosive atmospheres is required.
Technologies exist for the inspection of wall thickness and ovality in both maintenance facilities and on operational locations but are commercially available only as a third party service; only one such service is known to be certified for explosive atmosphere use and all require trained technicians.
This paper presents a new wall thickness and ovality measuring tool engineered for reliable field use and which needs no specialist inspection personnel. By combining custom-designed fiber-optical transducers and magnetic flux leakage (MFL) principles, electrical apparatus is eliminated from the explosive area and certification is not required. The unique fiber-optic system design contributes significantly to the ruggedness and reliability of the inspection system.
Performance data from field service will be presented.
Estimation of Saturation Height Function Using Capillary Pressure by Different Approaches
Authors: Jamiolahmady Mahmound , Sohrabi Mehran , Tafat Mohammed 
Published: December 2007

Abstract
The saturation-height function greatly impacts reserve calculations and is used by geologists or reservoir engineers to predict the saturation in the reservoir for a given height above the free water level. If cores are preserved, the water saturation information can be obtained directly. However, cores are often subject to changes from their original state before brought to laboratories. Hence, capillary pressure (Pc) curves measured on different core samples of a heterogeneous formation are usually correlated to porosity, permeability, and/or rock type using various techniques to generate field wide saturation height function.
This paper evaluates performance of six saturation-height methods (i.e., Leverret-J[1], Cap-Log[2], Johnson[3], Cuddy et al. [4], Skelt-Harrison[5] and Sodena[6] methods) employed in the oil industry.
Measured capillary pressure data and core properties for a well in one of the North Sea reservoirs were used with rock permeability varying from less than 1 mD to over 1000 mD. We have reviewed advantages and disadvantages of each method while comparing the output of each method with saturation obtained from the log data. The results indicated that Skelt-Harson method with coefficient independent of core properties, a simple average Pc function, could be the best option and complicating the functional form by including the porosity and/or permeability data might inversely impact the predictions. Furthermore, modifying Cap-Log Cuddy et al. and kelt-Harison by including the core permeability data in the mutli-regressione exercise resulted in higher errors confirming that increasing the degree of freedom does not necessarily mean a better performance.
Faster Seismic History Matching in a UKCS Reservoir
Authors: Stephen Karl D. , Shams Asghar , MacBeth Colin 
Published: December 2007

Abstract
In seismic history matching, we perform a computer assisted history match to conventional production data but also include the spatio-temporal information offered by time-lapse (4D) seismic to further constrain the model. Good predictive models can only be found with a suitable search of the space of uncertain parameters such as permeability, porosity, net:gross and fault transmissibility.
We present a method of history matching that speeds up the search process. By using streamlines in place of a finite difference simulator, a factor ten speed up in simulation can be obtained. The model accuracy is slightly diminished affecting both the predicted well data along with saturations and pressures that are used to predict the 4D signal. We show how to reduce any bias effects by calibrating the model error and including it in the misfit calculation.
The method has been applied to the UKCS Nelson field using six years of production history and two seismic surveys. The field is maintained above bubble point and is ideal for streamline simulation. We compare the use of the finite difference simulator with the streamline method in history matching when we change net:gross and vertical permeability properties. By addressing the mismatch in seismic data together with production, we improve our predictive capability.
A proper parameter search increases the reliability of predictions made using simulations, and has great benefits for reservoir management. Decisions regarding water and gas handling, well maintenance and optimisation of production can be made with greater confidence and new wells can be planned with reduced risk.
History Matching Using Local Gradual Deformation
Authors: Gervais V. , Gautier Y. , Le Ravalec M. , Roggero F. 
Published: December 2007

Abstract
The gradual deformation method (GDM) is a geostatistical parameterization technique that generates a sequence of realizations evolving smoothly while preserving the statistical characteristics of the model. Combined with an optimization algorithm, it enables to constrain 3-D reservoir models to both static data (log data, prior geological information…) and dynamic data (production data such as pressure or water cut at wells…).
The gradual deformation is based on the weighted combination of several realizations using deformation parameters. It can thus be applied both globally, with the same deformation parameters for the entire domain, or locally. In this case, the domain is partitioned into non-overlapping subregions and each of these areas is attributed one or several deformation parameters independent from the other region parameters. This method, called local GDM, is more flexible than the global one. It can have several applications such as the integration of new data to improve the reservoir model, or the simultaneous deformation of regions with different geological properties or dynamic behaviors. An application of this method for history matching on a real data set is proposed in this paper.
One major issue when using local deformations is the definition of the reservoir partitions. Several approaches are considered in this paper, mainly based on the characterization of drainage areas and on geometrical criteria using Voronoi diagrams.
History Matching 4D Seismic Data with Efficient Gradient Based Methods
Authors: Emerick Alexandre Anozé , de Moraes Rafael Jesus , Rodrigues José Roberto Pereira 
Published: December 2007

Abstract
Time-lapse seismic is an important subject in the Petroleum Industry. Going beyond the qualitative interpretation of the seismic data, including quantitative information in the flow simulation model updating process, is a highly desirable goal. 4D seismic data give information far away from the wells, potentially allowing much richer parameterizations of the reservoir model in the history matching process. Since these parameterizations tend to be described by a large number of parameters, efficient algorithms are needed to tackle these problems.
This paper describes some efforts to integrate time-lapse seismic attributes into a derivative-based assisted history matching tool developed in a previous project1. The implementation of the seismic attributes derivatives using the forward and the adjoint method into a commercial reservoir flow simulator is described. The calculated derivatives are used in an optimization algorithm based on a trust-region Quasi-Newton method to minimize the mismatch between observed and simulated data from production and seismic.
Good results were obtained in several synthetic cases adjusting seismic and production data.
Tracking the State and Diagnosing Downhole Permanent Sensors in Intelligent-Well Completions With Artificial Neural Network
Authors: Aggrey G. H. , Davies D. R. 
Published: December 2007

Abstract
Permanent downhole sensors are extensively used in Intelligent Well completions. Typically, their numbers increase with the number of controllable zones. Replacement of a failed sensor rarely occurs in practice even when data is known to be incorrect (or completely missing) due to the cost implication of a workover. However, these sensors serve as the optic nerve for achieving the vision of Real Time Optimization. They measure parameters of interest (Monitoring) which is the first stage of the production optimization loop frequently known as "Measure, Analyze and Control", which will manage the reservoir and well performance. The reliability of permanent downhole gauges is not 100% throughout the well life. It is therefore imperative to authenticate whenever possible, the operational state of these downhole sensors. Such authentication will allows greater confidence to be placed in the data they supply.
This paper discusses how authentication is achieved by comparing the soft (computed) sensor value predicted by an Artificial Intelligence technique with the actual hard data. This approach is demonstrated using a real case data. An Artificial Neural Network (ANN) is trained with multi-dimensional historical downhole data. The ANN is shown to be able to validate continued proper sensor operation or diagnose a future malfunction of any sensor. It will also be shown that the trained ANN can predict parameters such as the zonal BHP, with sufficient accuracy and that they serve as back up to maintain reservoir management operations.
Detailed Special Core Analysis Program: A Key to Aggressive Field Development Planning—Rajasthan, India
Authors: Beliveau Dennis 
Published: December 2007

Abstract
In 2004, several large oil discoveries were made in high-permeability multi-layered Fatehgarh sandstone reservoirs in Rajasthan, India. The fields contain light but viscous paraffinic oils with wax appearance temperatures very close to reservoir temperature. As these were the first Fatehgarh discoveries in the region, no special core analysis (SCAL) information existed for the unusual oil-bearing rocks. A fast-track comprehensive SCAL program to determine wettability, relative permeabilities, capillary pressures, and initial and residual oil saturation was implemented within weeks of the first discovery. This data was critical to the design of waterflood patterns and facilities for these intermediate- to weakly oil-wet reservoirs.
The value of a comprehensive up-front SCAL program is clearly demonstrated. Although acquisition of the SCAL data cost ~US$5million, it played a crucial role in justifying a change in field development plans involving closer well spacing, higher injection volumes and larger surface facilities.
A statistically significant number of SCAL measurements were made on representative Fatehgarh samples. In general, reservoir rocks have the low initial water saturations (Swi~5%), long oil drainage tails and low residual oil saturations (Sorw&lt;15%) typical of intermediate- to weakly oil-wet reservoirs (Amott-Harvey wettability index −0.33 ± 0.27). Early quantification of these characteristics by facies and their implementation into stochastic static and dynamic reservoir models were critical to development of a technically sound field development plan.
The 2004 discoveries in an industrially less-developed part of India are projected to be on production by 2009. Large fast-tracked investments in infrastructure and oilfield development were significantly shaped by the early acquisition of a comprehensive SCAL dataset. The data helped to optimize the different waterflood designs chosen for the different fields (pattern floods vs. edge line drives, well spacings, vertical vs. horizontal wells, etc.) and to quantify the expected oil and water production profiles from these very high-quality intermediate- to weakly oil-wet reservoirs.
Free-Fall Gravity Drainage in Fractured Matrix Blocks: Experimental and Network Modeling Simulation Findings and Observations
Authors: Mollaei Alireza , Haghighi M. , Maini B. 
Published: December 2007

Abstract
Free Fall Gravity Drainage as an important recovery mechanism was investigated and analyzed experimentally and by numerical (network model) simulation.
Sets of glass micromodels with real pattern of porous media and two numerical network model simulators were prepared in forms of fractured and non-fractured models to study and analyze the Free Fall Gravity Drainage recovery mechanism experimentally and by simulation. After validating the network model simulator, analysis of experimental and simulation results leads to some interesting findings and observations as follow:
Based on network modeling simulation, direction of flow through fracture network shows that the oil in the middle horizontal fracture usually flows from one end of fracture to the other end, however in relatively small fracture apertures the oil from both vertical fractures at the ends of middle horizontal fracture flows into the horizontal fracture and then sinks downward to the lower matrix block. This means in relatively small fracture apertures, block to block interaction coefficient (α) reaches to 100%. Another point is that, it was observed from network model simulation data that this critical fracture aperture is a function of pore and throat sizes.
Also, experimental and simulation results confirm that there is no break through of gas in free fall gravity drainage process. In addition a new mathematical approach (by means of flow potential and control volume concepts) to block to block interaction effects (Capillary Continuity and Reinfiltration phenomena) is presented to explain and interpret the mechanism of occurrence of these phenomena. This approach proves mathematically that decreasing the fracture aperture leads to increasing the fracture capillary pressure which in turn intensifies the feeding rate of liquid bridge (in the middle horizontal fracture) from upper block and lowers the discharging rate of liquid bridge from lower matrix block. Therefore, the liquid bridge can be more stable between the matrix blocks. As a result, fracture capillary pressure has positive effect on oil recovery from matrix blocks.
Finally, a new approach for determination of the matrix block threshold heights at the end of free fall gravity drainage is presented and used to prove that matrix block threshold height inreases with increasing the matrix block height. Also, it will be proved that matrix block recovery factor increases with increasing the matrix block height although matrix block threshold height increases too.
An E-Line Solution to Sand and Scale Remediation in High-Angle Wells
Authors: Schwanitz Brian , McKay Alex 
Published: December 2007

Abstract
Sand accumulations in high angle wellbores inhibits production, plugs completions, erodes hardware and blocks access to downhole jewelry, such as valves and sliding sleeves. Bailing on sick line wire is the preferred, low cost method to clean sand and debris in vertical wells but slick line can not often reach in high angles. Conventional remediation methods for high angles use either Coiled Tubing or an expensive rig to remove sand and debris. This paper presents a rigless alternative to sand, debris or scale removal utilizing a combination of well tractor technology and a new vacuum/bailer system all conveyed on electric wireline.
Tractor technology is a proven tool as a conveyor of services in high angle wells. Combining a tractor with a well cleaning system provides the means of accessing and removing debris either selectively in one run or over a general area in multiple runs. These electric line powered tools can be mobilized quickly with less crew, and for far less cost than a coiled tubing mobilization. Following the sand removal, evaluation of the source of the sanding problem can then be performed with E-line inspection services during the same rig up.
Three case examples will be presented demonstrating the three different cleaning methods: liquid environment vacuum system, dry environment auger system and scale milling system. Each example will detail the unique cleaning head and bailer system used for the given completion and problem.
A Process Delivery Template for an Underbalanced Coiled-Tubing-Drilling Project From Concept to Execution
Authors: da Silva T. P. , Kavanagh T. , Rennox J. , Savage P. , Capps J. 
Published: December 2007

Abstract
Underbalanced coiled tubing drilling (UBCTD) has been utilized more frequently in recent years and can provide significant economic benefits when applied in the proper field setting. UBCTD requires a comprehensive evaluation of the proposed application, a commitment of resources by the operator and service providers, and a clear understanding of, (and tolerance to), the learning curve. As established coiled tubing drilling operations continue to push the technical limit forward, advances are assured.
The main scope of this paper is to document a template or flowchart for putting together a UBCTD project, covering everything from initial concept up to drilling the first well.
Production Optimization With Intelligent Wells
Authors: Emerick Alexandre Anozé , Portella Ricardo Cunha Mattos 
Published: December 2007

Abstract
This paper describes an implementation of method to optimize the production in intelligent wells varying the wells inflow control valves settings using an optimization algorithm coupled to commercial flow simulators. The optimization is based on direct search methods. The optimization algorithm was coupled with two different commercial flow simulators and has been applied in two real Brazilian offshore fields to quantify the benefits of intelligent wells over a base case with conventional completion. The first field has three horizontal wells, two producers and one water injector, completed in two zones totalizing six inflow control devices. In this case, different scenarios have been analyzed varying the downhole valves type – on-off and multi-position. The results have shown that the intelligent wells scenarios increased the recovery factor and reduced the production and injection of water when compared with the base case (conventional completion). The second field has fifteen wells – nine producers with binary valves and six water injectors with six-position valves – producing and injecting in two or three zone totalizing 39 downhole valves to be optimized. In this case, the results have shown a significant increase of the expected cumulative oil production when compared with the base case.
Classic Models of Calculation of Influx: A Comparative Study
Authors: Marques J. B. , Trevisan O. V. , Suslick S. B. 
Published: December 2007

Abstract
Reservoir engineers usually work under much uncertainty. Among the several sources of uncertainty in reservoir management, calculation of the water influx from adjacent aquifers is undoubtedly one of the most important. Several models have been proposed for quantifying the influx of water accumulated into the reservoir. Among the classic models, the most used are van Everdingen & Hurst, (1949), Hurst modified (1958), Fetkovich approximate (1971), Carter & Tracy (1960), Allard & Chen (1984), and Leung (1986). This work will deal, in a comparative way, with the total influx of water by the aquifer performance as a function of time, taking as the base case the model proposed by van Everdingen & Hurst (1958), because this is the best in terms of solution of the diffusive equation. All analyses in this work were done in computer spreadsheets using the equations proposed by the authors of each model. In this comparison it is possible to analyse the water influx into the reservoir as a function of time, and the relative error of each model against the base model. Besides the instructional value of summarizing in a single paper several classic models of aquifers, one additional purpose of this work is to alert against the inadequate use of the Fetkovich model, as commonly found in flow simulators and in material balance programs, when the ratio between the radius of the aquifer and the radius of the reservoir is below 12. In the conclusions, some corrections of mistakes found in tables and formulations published in the original papers are presented, as well as alternative formulations for the calculation of the aquifer productivity index, specifically with regard to the original publications of Fetkovich, 1971 and of Leung, 1986.
Placement of Permanent Downhole Pressure Sensors in Reservoir Surveillance
Authors: Izgec B. , Cribbs M. E. , Pace S. V. , Zhu D. , Kabir C. S. 
Published: December 2007

Abstract
This paper probes the gauge placement issue with regard to yielding quality formation parameters, unaffected by wellbore effects. Non-physical or biased results may result if the wellbore effects go unaccounted for.
We used a wellbore/reservoir simulator, which conserves mass, momentum, and energy to develop a comprehensive understanding of the gauge-placement issue. First, we reproduced a field example from a deepwater asset to demonstrate the simulator's capabilities. In this example, we matched the bottomhole pressure, and pressure/temperature monitored about midpoint of the flow string during a multirate test sequence lasting some 60 hours. Calculations show that thermal effects are exacerbated by increasing flow rate and increasing gauge distance from the perforations.
Second, we performed a detailed uncertainty analysis with experimental design. Variables included in this analysis were perforation-to-gauge distance, permeability, geothermal gradient, flow rate, fluid viscosity, thermal conductivity of annular fluid and formation, and mechanical skin. This analysis sheds light on relative importance of these variables on our ability to extract formation parameters. Simple correlations are developed for designing gauge placement in many environments.
Economic Viability of Gas-To-Liquid Technology
Authors: Garrouch Ali A. 
Published: December 2007

Abstract
The Gas-to-Liquid (GTL) industry is witnessing a monotonic growth that is expected to increase the liquid fuel production from currently 51,000 bbl/day to approximately 1.3 millions bbl/day by year 2015. GTL appears to be a viable and promising solution for the future of alternative and cleaner energy technologies. Recent advances in GTL technology have lowered the cost to the level where GTL plants are profitable at crude oil prices of $23/bbl, for a 10% rate of return, and an annual operating expenditure (OPEX) that is 7% of a $40,000 per-barrel-a-day capital expenditure (CAPEX). Technology advancements, reflected mainly in the reduction of the capital costs are likely to lower this price to about $11.5 for a 10% rate of return and a 7% OPEX of a $20,000 PBD CAPEX. At a current CAPEX value of approximately $35,714 BPD for a number of oil companies, crude oil price lower than $20/bbl would place this particular GTL venture in an area of economic uncertainty.
The expansion of the GTL industry is likely to place the GTL industry in direct competition with the liquefied natural gas (LNG) industry for access to natural gas supply. By year 2015, GTL units are likely to consume about 4.75 tcf/year and LNG units will consume approximately 7.25 tcf/year. Together, this represents a fifty-year consumption of 600 tcf from the world natural gas reserves. This fifty-year consumption of both GTL and LNG plants represents only 20% of the proven stranded gas reserves that currently stand at about 3006 tcf. The global GTL industry will consume about 8% of the world stranded natural gas reserves, or 4% of the world proven natural gas reserves, for the same 50-year production-period. These statistics indicate that there are plenty of gas resources for the continuity of both the GTL and the LNG industries in the long term future.