bluuebunny/crossref_metadata_2025_split huggingface dataset:
Microbial Monitoring to Minimise Corrosion and Formation Damage in the Oil Industry
Authors: Spark I. , Mutch K. 
Published: December 2007

Abstract
It is accepted that sulphate reducing bacteria (SRB) and certain general heterotrophic bacteria (GHB) can promote pit corrosion of topside and downhole equipment and cause formation damage in the reservoir including H2S souring. In order to inhibit microbial growth and hence minimise these damage mechanisms, it is necessary to impose a strict microbial monitoring regime that can be used to optimise any biocide treatments. There are two major considerations relating to microbial monitoring which must be taken into account which are planktonic microbes (those in suspension) and sessile microbes (those attached as a biofilm). By monitoring the numbers of SRB/GHB entering and leaving each component of the topside process system it is possible to determine whether each is under good microbial control. If numbers are found to increase from inlet to outlet, then biocide treatment at a suitable concentration, can be used to treat the fouled components before pit corrosion or H2S production becomes a serious problem within the component. If the biocide treatment is not performed in time the system downstream may also become contaminated. By carefully monitoring each process system including injection water, firewater, cooling medium, and production systems, it is possible to extend the process equipment lifetime considerably, resulting in a major saving in equipment replacement and lost shut down time. This paper describes the microbial monitoring techniques required to minimise corrosion, biopolymer, insoluble metal sulphide and H2S production both topside and downhole.
Reservoir Management & Simulation of Al Rayyan-An Offshore Carbonate Oil Field Under Strong Aquifer Drive
Authors: Nutakki R. , Heaviside J. , Noman R. , Al-Othman I. J. 
Published: December 2007

Abstract
The Al Rayyan oilfield, offshore Qatar presents an interesting case of natural water drive. This paper presents the results of investigations to understand the production mechanisms in the main producing zone in the field (Arab C). This zone is a thin, low relief Arab carbonate reservoir with high porosity and permeability. The reservoir has a strong natural aquifer drive and the reservoir pressure has remained close to the original pressure during the 5-year initial production phase. The field was developed with horizontal wells to provide sufficient productivity in the thin reservoir. The main phase of field development, planned following these studies, is now underway with the drilling of additional sidetracks and further longer, carefully placed horizontal wells. Results of the first two new wells are described.
The initial production stage experienced early water breakthrough, water cut rising at first and then stabilizing. Oil production has continued at decreasing cuts throughout the five years. The reservoir studies described in this paper were used to determine the optimum well type and placement for the main phase of development. The offtake strategy was also investigated and decisions regarding offtake rate, level of water handling and other development parameters were made under the guidance of the model results.
The modeling has provided a thorough understanding of the water and oil production mechanisms in the reservoir. When wells are put on production there is rapid coning of water into the wells. The movement of the water is primarily vertical due to the small thickness of the reservoir and the strong aquifer underneath the Arab C reservoir. The size and shape of the cone stabilizes quickly after it is formed and this leads to the characteristic leveling of the WOR curve seen in the Al Rayyan wells with time. Most of the oil produced does not come from the cone underneath the well but is produced by lateral movement of oil from the region around the well.
Results show that despite the coning of water under the horizontal wells oil recovery from the field is increased at higher offtake rates. In practice the offtake rate is limited by the capacity of the separation facilities. Well numbers and individual well rates should be designed to ensure full utilization of this capacity. This unusual result is due to the geometry of the field, which is so extreme that no economic rates produce gravity stable flow. Oil recovery becomes a function of the extent or maturity of the (natural) water-flood.
Water Saturation Computation From Laboratory, 3-D Regression
Authors: Hamada G. M. , Al-Awad M. N. J. , Alsughayer A. A. 
Published: December 2007

Abstract
An accurate determination of initial oil in place in the early life of reservoirs or an evaluation of a developed reservoir is required to well estimate the hydrocarbon volumes. Modified Archie formula (Sw = (a Rw / ϕm Rt)1/n) is the basic equation to compute water saturation in clean formation or suitable shaly water saturation model in shaly formation. The accuracy 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 speculations. There are many factors affecting porosity exponent, m, saturation exponent, n and tortousity factor, a. Therefore, it is very difficult to fix Archie parameters and neglecting 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. This 3D technique provides simultaneous values of Archie parameters. Also, the 3D technique 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 the 3-D technique in comparison with three other techniques: 1) common values of Archie parameters, 2) conventional technique and 3) core Archie parameter estimation (CAPE) technique. The comparison among the four techniques has shown that 3-D technique 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 obtained from the four techniques, have been obtained 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 technique. The effect of saturation exponent on the accuracy of water saturation computation was tested using Archie's parameters derived from conventional technique and 3-D technique in the two wells.
Identification, Quantification and Analysis of Subsurface Uncertainties Associated with Reservoir Description. Assessment of its impact on the Development of a Miscible WAG Injection Project with Horizontal Wells
Authors: Ayoub M. , Negahban S. , Gomes J. S. , Dawood A. , Mahdi A. , Al-Baker S. 
Published: December 2007

Abstract
This paper addresses identification, quantification and analysis of subsurface uncertainties associated with development of a reservoir description and its impact on development of a field under miscible WAG process. Uncertainty analysis is an essential part of development, engineering and production of any oil or gas reservoir. As a result of a limited number of wells in the field, uncertainties in reservoir description are great. A static reservoir model is constructed using information from 18 wells and 3D seismic. An integrated modeling approach involving geology, petrophysics and geostatistics are applied in determining final property models. Several stochastic modeling techniques are applied to build the porosity, permeability and saturation models and multiple realizations are used for the uncertainty quantification. Porosity and water saturation are modelled using the Collocated Co-kriging method with depth as soft data. The permeability model is built using the Cloud Transform technique. Core and probe-permeameter measured permeability data are used to assess the heterogeneity of permeability at different scales. Fracture analysis is conducted using image logs (FMI). A full field compositional model was built to evaluate the field reservoir performance under various development scenarios. The field has been in Early Production Scheme (EPS) since early1990 and is scheduled to come on stream by December of 2005.
Effective Permeability Modeling: Geostatistical Integration of Permeability Indicators, OffshoreAbu Dhabi
Authors: Bushara M. N. , El Tawel A. , Borougha H. , Dabbouk C. , Qotb M. 
Published: December 2007

Abstract
The paper describes a method for modeling reservoir true effective k incorporating k from core, fractures & well test. A 3D permeability model is developed based on detailed lithotype mapping within which horizontal matrix permeability is simulated. Comparison of modelled permeability with actual test permeability values suggests that there is a genuine permeability contribution from fractures in the reservoir. The resultant model is thus combined geostatistically with fracture k so that the final permeability matches well test permeability. We used strain field as an indicator of fracture locations and hence to flow from them. Strain field over the reservoir, which correlates with test permeability, is obtained from curvature analysis and calibrated to strain calculated from core fractures. High strain areas are set to be associated with highly fractured zones that are commonly marked by increased conductivity. Computer geostattistical module computes fracture permeability from a power-law relationship and conditions it to match interpreted test permeability in 3D space. The geostatistical method offers means of predicting fracture permeability distribution field-wide and better accounts for water encroachment trends. The results helped achieve better history match results more easily than would have been possible without the combined model.
Evaluation of the polymeric materials (DVB copolymers) for produced water treatment
Authors: Carvalho M. S. , Clarisse M. D. , Lucas E. F. , Barbosa C. C. R. , Barbosa L. C. F. 
Published: December 2007

Abstract
Copolymers beads based on methyl methacrylate (MMA) and divinylbenzene (DVB) were prepared by suspension polymerization technique. For the copolymer synthesis, the following reaction parameters were varied: diluent type, dilution degree and divinylbenzene content. The copolymer porosity and specific surface area (BET) were determined. The copolymers were used to prepare columns, which were tested as oil remover from PETROBRAS produced water. Columns containing only one kind of polymer (polyDVB) achieved a oil content reduction of 84.9%; containing two different polymers (polyDVB and poly(MMA-DVB)) reached 89.1%. The results showed that the distinct chemical composition copolymers can retain different compounds from the produced water. The columns can be re-used after a regeneration process.
Cuttings reinjection to shallow undersea formation: The Geomechanical acceptance analysis using hydraulic fracturing simulator
Authors: Shioya Y. , Yamamoto K. , Fujieda Tadaomi , Kikuchi Shuichi , El-Khatib Hassan 
Published: December 2007

Abstract
Operation availability, environmental safety, and storage capacity of the slurrified cuttings re-injection into a shallow, permeable formation off-shore Abu Dhabi was evaluated using a computer simulator for hydraulic fracturing.
For the study, Umm Er Radhuma formation of Z field is chosen as the disposal formation, meanwhile Rus formation is regarded as the cap rock over the formation for isolating injected fluid and solid from propagating to seabed. A Geomechanical model of the formations which includes stress regime, formation pressure, rock mass properties, and leak-off characteristic was established with available data from literatures, wire line logging, and water disposal history in the same formation.
The numerical model, which is developed by the authors, provides the estimation of injection pressure, fracture geometry and size, and storage volume of the slurry with a modeled injection schedules. The effect of solid particle concentration which may reduce pressure near fracture tip and cause screen off is taken into account for the fluid flow analysis and the determinatin of the fractrue geometry.
Enhancement of Stimulation Treatment of Water Injection Wells Using a New Polymer-Free Diversion System
Authors: Safwat Mohamed , Nasr-El-Din Hisham A. , Dossary Khalid , McClelland Ken , Samuel Mathew 
Published: December 2007

Abstract
Vertical seawater injectors for a carbonate reservoir in Saudi Arabia have an injection zone (open hole) of approximately 200 ft. This reservoir has drastic permeability variations. Acid stimulation without proper diversion normally results in undesirable stimulation of the high permeability streaks. Therefore, acid diversion plays a key role in improving both the post-acid, well-injectivity and injection profile.
Various diverting agents have been used to improve the acid distribution during acid injection, including wellbore gels, foams and in-situ gelled acids. The use of polymers is an excellent means of diversion.1,2 However, evaluation of polymeric systems has demonstrated formation damage due to residual polymer, which is considered unacceptable, especially for water injection wells.3 Conventional foams have also been tested with good success.
In the present study, the use of a polymer-free viscoelastic surfactant (VES) as a diverter system is investigated and compared with in-situ gelled acid and foams. The VES is a two-component system, and in the presence of salts, the surfactant molecules associate to form rod-like micelles. These micelles can entangle with each other and form a three dimensional network, responsible for the high viscosity of the system.4,5 This non-damaging "surfactant gel" can be broken completely by injecting mutual solvent or injection water. This added advantage eliminates the need to flow back the well following acid treatments.
Laboratory studies demonstrated up to 2-fold increase in viscosity and nearly 20-fold increase in foam stability compared to foams containing polymers. The properties of VES solutions are independent of the salinity and pH of the mixing water.
Bullheading the acid enables the operator to pump these treatments at high rates, which are needed in some cases. Pumping pressure, post-acid injectivity history and injection flow profile of several seawater injectors indicate good stimulation results and better acid diversion across the whole target zone.
This paper presents the first application worldwide on the use of VES technology in water injection wells. A total of six stimulation treatments were performed using this technology, one treatment using coiled tubing (CT) and five by bullheading.
The VES technology provides a solution for heterogeneous carbonate reservoirs, and eliminates formation damage induced by the polymers present in the conventional diversion systems. Stimulation using the VES system on six wells resulted in an injection increase of more that 45,000 bbl of water per day, much higher than similar treatments where conventional foams were used.
Automated well control increases performance of mature gas-lifted fields, Sendji case
Authors: Boisard O. , Makaya B. , Nzossi A. , Hamon J. C. , Lemetayer P. 
Published: December 2007

Abstract
This paper reviews one recent example of benefits of the implementation of a full control of wells tool offshore Guinea Gulf.
This field case confirms the full control of wells smart automation increases by 10% the daily oil production of a mature field. It also confirms production increase above 20% under sensitive situations.
Using measurements and adju stments only at well head avoids work over and ensures robustness. Setting parameters related to physics such as ranking or starting lift gas tunes the standard sequences to any well and topsides.
Other fields applications include dual gas lift and dynamic control of gas coning to maximize recovery.
Upgrading the well control to digital allows a remote operation. High quality data improves understanding the behavior of mature wells.
Beyond this supervision, two levels of control algorithm provide with a continuous and autonomous control of the unmanned platforms.
This smart control monitors and automates both single well and platform levels to handle transient phases and to face unforeseen behavior of reservoir, wells and facilities. Automated sequences help the operators if any trouble on a well or topsides. Remote manual operation cannot account continuously and accordingly for many wells particularly during hurried restart phases.
This smart control increases the uptime and efficiency of wells and topsides. It stabilizes at source the compression and topsides intake. It also increases the recovery factor.
Introducing an Enhanced Calibration Technique for Core-Log Rock Mechanical Parameters: New Shift Calibration and Recursive Filtering Techniques
Authors: Awal Mohammad R. , Mohiuddin Mohammed Ahmed 
Published: December 2007

Abstract
We have developed two new methods for core-log data calibration. These methods are applied in tandem (in series). We have demonstrated that the new approach in calibration may result in an order of magnitude of difference. The results can significantly alter the way various well designs are done, including hydraulic fracturing, optimized borehole trajectory, and well intervention.
Traditionally, the measurements of rock properties have been based on cores. However, the coring process has always been considered to be costly, and mitigated by dependence on logging. Although logging provides a distinct advantage by providing continuous (at least at a half-foot depth interval) measurements of data, the core-based measurements are still considered superior and more reliable. Hence log-based data are calibrated in terms of the limited core-based data.
The most common method applied is the least squares method (Ahmed, 1988). However, the least squares process alters the quality of the log-based data, not only in magnitude but also in trend. It is the second aspect of data alteration that is questionable. It may smear the true variability of rock properties change as a function of depth. We have found, with actual well data, that the smearing of data trend may occur to the extent that a flat response may result where actually the rock property varies rapidly with depth. Maintaining the true rock property change with depth, for example, the uniaxial compressive strength (UCS), can be crucial in designing a successful hydraulic fracture job. Since it is highly desirable to contain the fracture height within the payzone, the accurate UCS values in the over- and the under-burden rock strata must be known with respect to that in the payzone. Similary, accurate zonal permeability information in necessary in order to diagnose thief zones, and/or shut-off water producing zones.
Development of a Petroleum Contractual Strategy Model
Authors: Ramadan N. B. , Zekri Abdulrazag Y. 
Published: December 2007

Abstract
The development of a petroleum exploitation strategy is essential for any country, which needs to develop its indigenous petroleum resources, see Fig. 5. A petroleum exploitation strategy is the series of policies relating to licensing, taxation, royalty, and general legal instruments i.e. contractual agreements, see Table 1 developed by the state in order to ensure the orderly development of petroleum exploration and production. In the absence of a clear petroleum exploitation strategy, the international oil companies would not be able to assess the political and economic risks involved in any petroleum exploitation venture, no matter how low the technical risks are.
Since the International Oil Companies are major sources of the intensive capital, and sophisticated technologies needed for exploration and development of petroleum resources, it is essential for a country to formulate a coherent and well balanced petroleum exploitation strategy. This should be consistent with its social and economic goals and at the same time allow the international oil companies to generate economic profits that in some way relate to the level of risk involved in obtaining these profits. This research project has focused on the study of the different petroleum contractual agreements between host countries and international oil companies worldwide, and has culminated by the development of a contractual strategy model for the exploitation of the petroleum resources. The development of the model has been preceded by a comparative and evaluative analysis of the international and host country petroleum agreements. The main features, advantages and disadvantages of each type have been summarized and tabulated. The suitability of the different agreements, in the view of the rapidly changing environment of the petroleum industry, has been evaluated. A new contractual model for the exploitation of petroleum resources in the Middle East is developed in this project. The Model required the development of eight different strategies, which relate to the possible combinations of three strategic factors that were found to be of the greatest importance. It has been proposed to use this model to evaluate and guide the development of the future Middle East petroleum exploitation strategies.
A New Ion Exchange Process for Softening High TDS Produced Water
Authors: Brown Craig , Sheedy Michael 
Published: December 2007

Abstract
Weak acid cation (WAC) resins are normally utilized for softening high TDS produced water. The main disadvantage of the WAC process is that the resins require regeneration with hydrochloric acid followed by sodium hydroxide. This is expensive and necessitates the utilization of exotic, corrosion resistant alloys for construction.
Strong acid cation (SAC) ion exchange processes employing only brine regeneration (i.e. no acid or caustic) are much simpler and less expensive, however the SAC process is normally restricted to low TDS (&lt;3000 mg/L) waters. A new ion exchange softening flow-sheet that uses brine regeneration has been developed based upon the Recoflo short-bed ion exchange process. Recoflo makes it possible to use extremely high service flow rates through very short (15 cm) resin beds, while achieving low hardness leakages. The key to applying this to high TDS produced water is the use of high purity brine regenerant. A novel ion exchange process which employs only water for regeneration (i.e. no chemicals) has been developed for purifying the brine. This paper explains the rationale for the process using ion exchange equilibrium calculations and then shows pilot plant and field data.
New Tools for Heavy Oil Dehydration
Authors: Warren Kenneth W. 
Published: December 2007

Abstract
Heavy oils are becoming increasingly attractive from the standpoint of availability of reserves and economic status as "opportunity" feedstocks. However, they also bring some complex dehydration problems including high levels of suspended solids, conductive organic species, and varying amounts of semisoluble and precipitated organic materials. Meeting these challenges requires new techniques in both the areas of chemical treatment and dehydrator design. This paper focuses upon improvements in hardware design.