bluuebunny/crossref_metadata_2025_split huggingface dataset:
Approval Process for New Oil and Gas Field Development in Trinidad and Tobago
Authors: Rajnauth Jerome , Rudder Marc , Bradshaw-Niles Penelope 
Published: December 2007

Abstract
The Ministry of Energy and Energy Industries has the responsibility under the Petroleum Act to approve new oil and gas field developments. During recent years, many new fields have been developed and it is expected that this trend will continue in the future. Furthermore exploration work in deep and ultra deep waters will continue.
This paper describes the general process of approval by the Ministry of Energy and Energy Industries as well as information requirements related to new field development.
The authors hope this paper would be useful to any company involved in oil and gas exploration and development in Trinidad and Tobago and also those companies willing to invest here in the future. It is also the intent of the author that this information will be useful to other regulatory bodies around the world.
Liquid Inventory Management in Wet Gas Pipelines
Authors: Su C. , Rydahl A. , Shea R. H. 
Published: December 2007

Abstract
Production and transportation of wet gas in large diameter pipelines necessitate several operational issues to be addressed. Of particular interest is the liquid inventory management, which is essential to ensure efficient and save operation of the pipeline. This paper quantifies several options for liquid inventory management in such pipeline systems.
Often pipeline configurations include parallel pipelines. This allows for flexibility in operation of the pipelines, but at the same time introduces additional potential liquid inventory problems. At normal production rates, flow would tend to evenly distribute between two parallel pipelines with the same diameter since friction will be the dominant cause of flow resistance. At reduced production rates liquid would start to build up in the pipelines and unless proper attention is given, the in-situ liquid volumes may quickly exceed those of available separators and slug catchers.
The liquid build up can start at different rates for the two pipelines if there are differences in the pipeline profiles. Liquid build-up will also be influenced by how the liquid splits between the two pipelines at the pipeline inlets. Liquid buildup will increase the resistance of the flow in a pipeline.
The wet gas will often have an affinity to flow through the pipeline with less liquid buildup and thus less resistance. At the same time the parallel pipeline will produce less wet gas and thus gradually build up more liquid, as the production through that pipeline gets lower. Essentially the system is in an unstable condition and eventually one pipeline could end up with so much liquid that flow through it would cease. Very likely, the only remediation in such a case would be pigging.
Different scenarios are investigated to illustrate these potential problems and several suggestions to managing and operating the pipelines are presented.
Micro-Flux Control: The Next Generation in Drilling Process
Authors: Santos Helio , Leuchtenberg Christian , Shayegi Sara 
Published: December 2007

Abstract
Drilling wells for oil/gas has been increasingly challenging with the companies moving towards difficult environments. The problems faced in these locations range from very narrow margin between the pore (or collapse) and fracture pressures, pore pressure uncertainty, to high pressure and high temperature wells. Wells drilled in these scenarios using the conventional drilling method often do not get to total depth (TD), and even so, drilling can be extremely risky, with several kick/loss situations.
A new drilling method1 has been developed to overcome these problems, allowing a much safer condition, reducing the risks, and also permitting the wells to be drilled to TD much cheaper. Drilling is taken to the limit in a safe manner, extending each phase as much as possible, using the entire available mud weight window for that well.
The method uses the new concept of micro-flux control, which is based on detecting a minimum loss or influx of fluids, and instantly adjusting the return flow and, consequently, the bottom-hole pressure to regain control of the well. The well is drilled closed at all times, and the return flow from the well is compared to the predicted and ideal one, allowing detecting the discrepancies in a very short time.
This paper describes the basis of this new method and steps taken so far in the development. Field tests will be done very shortly, after the method has been tested in a simulated well condition. The use of this method allows wells to be drilled where today it has been impossible, extending today's technological limits way beyond the current boundary.
The Development and Application of a Software to Assist the Drilling Engineer During Well Control Operations in Deep and Ultra Deep Waters
Authors: Santos O. L. A. , Mendes J. R. P. , Ribeiro P. R. 
Published: December 2007

Abstract
This paper presents the development and application of an integrated computational tool to assist the drilling engineer regarding prevention and detection of a kick and its circulation out of the well when operating in deepwater and ultra deepwater drilling scenarios. This tool, called UNIKICK, provides the drilling personnel with information and several computational resources covering many aspects related to well control in those drilling scenarios.
The most important features provided by the system are as follows: (a) link to databases containing regulations, standards and operational procedures to be accessed from the rig site; (b) a module to display well control information and calculations such as kick tolerance, swabbing pressure, tripping and riser safety margin; (c) a killsheet which is calculated and displayed, automatically; and (d) an interface to show graphically the expected pressure behavior at selected points inside the well and fluids production during the kick removal process.
Through the interface, the user enters the data necessary to the calculation of the killsheet and to the simulation of the pressure behavior inside the wellbore and the flow rates of the fluids from the well, using a built-in kick simulator. This simulator was developed specifically for the system and accounts for the two-phase nature of the mixture of gas and drilling fluid and for the peculiarities of an ultra deepwater well/rig equipment configuration. The interface also displays the output data generated by the simulator in a graphical format together with animation capability for the gas that is circulated out the well.
To illustrate the usage of the system, the paper presents the results for three horizontal well control cases ranging from 1000 to 3000 meters of water depth.
The paper also suggests that the system can also be used as a very powerful instructional tool for training purposes.
Can We Visualize Drilling Fluid Performance Before We Start?
Authors: Galal Mohamed 
Published: December 2007

Abstract
The standard criterion for selecting a drilling fluid has been eliminating borehole instability and related problems. On the basis of current field experience, the drivers for developing formation-stabilizing agents and fluid technology always were related to basic concepts, such as quantitative mineralogy, dispersion tests, and swelling measurements, among others. This approach can exclude more important factors, including, but not limited to, geo-mechanics and pressure balances, that have a direct impact on the fluid deliverables, as well as overall drilling performance. The current thought process is ineffective at applying benchmarks, preventive measures, and risk assessment for most drilling operations. Further, it created a poor database that does not link quantitative fluid performance with borehole instability problems.
The paper presents a novel approach to the fluid selection process based on a unifying decision algorithm (decision tree). The challenge involves correctly identifying the relevant parameters and successfully applying the correct weighting to each of these parameters in the decision process based on the specific conditions of each project. By numerically incorporating all possible variables into a worksheet, the output recommendation should clearly rank each possible fluid option, the associated engineering risks, and provide a clear road map for realistically planning, executing, and measuring operational deliverables.
The objective of this work is to establish a universal definition for fluid selection criteria and to establish a base line, or road map, for data gathering to guide the process. The success of this approach also supports the idea of incorporating several high-performance fluid systems into one category, where each fluid has clearly defined performance measures supported by sound technical data. This process will facilitate an improved fluid selection process and increase chances for successfully completing challenging projects on time and under budget.
Fibrous LCM Sweeps Enhance Hole Cleaning and ROP on Extended Reach Well in Abu Dhabi
Authors: Cameron Charles , Helmy Helmy , Haikal Mohamed 
Published: December 2007

Abstract
Extended reach wells pose some unique problems to the drilling operation in the management of hole cleaning and torque and drag. Cleaning the hole without inducing an excessive equivalent circulating density (ECD), resulting in down-hole losses, can be a major issue when drilling extended reach wells. The reduced mud weight / fracture gradient window can limit pump rate making it difficult to achieve adequate solids transport, particularly in long 12 1/4" tangent sections.
Experience on world record extended reach drilling (ERD) operations led to the discovery that certain fibrous lost circulation materials (LCM) have the ability to enhance hole cleaning and dramatically reduce torque and drag in high angle and horizontal well-bores, as well as control losses. Optimised drilling practices, together with the application of engineered hole cleaning sweeps, can greatly improve drilling efficiency in extended reach wells.
This paper focuses on the successful application of fibrous LCM sweeps on the first extended reach well to be drilled in Abu Dhabi by the Abu Dhabi Company for Onshore Oil Operations (ADCO). In response to difficulties sliding in 12 1/4" hole, hole cleaning sweeps were routinely pumped from 9,462 feet, in the 63 degree tangent section, to final TD in 8 1/2" hole at 17,525 feet. Coupled with pipe rotation, these sweeps increased the rate of cuttings return to surface by up to 50% and frequently resulted in major improvements in the drilling rate. The effectiveness of these sweeps was monitored on surface at the shakers by visual means and downhole by means of annular pressure monitoring tools in the bottom hole assembly.
Multilateral Well Experience in Tight Clastic Reservoirs with Low Primary Recovery
Authors: Patra T. C. , Ghosh U. K. , Singh Raghuvir 
Published: December 2007

Abstract
Kalol field has multi-layered reservoirs with 11 pay horizons. Layers VII and X have better sand thickness. Gross lithology is mainly siltstone. The permeability ranges from moderate to poor and the primary reservoir drive mechanism is depletion. The reservoir pressure has declined from super-hydrostatic to substantially sub-hydrostatic at present. The productivity of vertical wells has fallen sharply and the field production rate has decreased. The well spacing is 600-700m, static bottom hole pressure shows high degree of variation. Two areas in sand KS-VII and KS-X were selected for drilling of multilateral wells. The wells have been drilled and put on production. The results are encouraging and the technology is proved to be an effective option for redevelopment of the field.
Managing the Government Gas Business in Oman using Hydrocarbon Field Planning Tool™
Authors: van Ravesteijn-Scott Elaine , van Berkel Jean 
Published: December 2007

Abstract
This paper presents a best practice workflow for managing the countrywide gas business in the Sultanate of Oman using Hydrocarbon Field Planning Tool (HFPT™). A Shell proprietary tool, HFPT is part of the FrontEnd Suite of applications that include the reservoir simulator MoReS and provides the capability for rigorous, integrated, subsurface-to-surface production forecasting for up to 25 years. HFPT hence facilitates the medium-to-long term planning and management of Oman&#39;s gas and gas-condensate fields and infrastructure development by accurately modelling the demand-supply balance of gas within the entire Sultanate.
HFPT provides a more realistic forecast than a stand-alone reservoir simulation for each field and, as such, can help with decisions regarding how to make the most efficient use of current assets while optimising future investments in new fields.
A Generalized Hyperbolic Decline Equation with Rate-Time and Rate-Cumulative Relationships
Authors: Chen Shing-Ming 
Published: December 2007

Abstract
Nearly all the decline curve equations used today are based on the Arps hyperbolic equation1. Many engineers prefer to use the exponential decline, which is a special case of the hyperbolic decline, to perform the decline curve analysis because it is easy to apply. Difficulties in using the hyperbolic equation are attributed to the decline rate variation with time and the changing initial rate or time in the production forecast.
Reference 2 presents a generalized rate-time hyperbolic equation which can successfully resolve the above difficulties in predicting the future rate. For the reserve estimate, however, the needed rate-cumulative equation is not being discussed.
In this paper, a rate-cumulative equation is derived for the reserve estimate. Using the generalized rate-time and rate-cumulative hyperbolic equations, the decline curve analysis can be performed to predict the future rate and estimate the recoverable reserve. These equations are further generalized to accommodate the multiple decline periods which may occur in the production forecast due to field or well optimization.
Estimation of Aquifer Parameters Using the Numerical Inversion of Laplace Transform
Authors: El-Khatib Noaman A. F. 
Published: December 2007

Abstract
A new method is presented for the estimation of parameters for a circular aquifer by nonlinear regression analysis using numerical inversion of Laplace transform. The parameters estimated are the relative aquifer size ReD, the storativity hfCt and the transmissibility kh/μ. These parameters are necessary to calculate water influx needed in performance prediction of oil and/or gas reservoirs by material balance based methods.
Water influx data are fitted to the van-Everdingen and Hurst (VEH) unsteady state solution to obtain the required aquifer parameters by nonlinear regression analysis using the method of least squares. Because the solution in Laplace space is simpler than the solution in the real time domain, numerical inversion of Laplace transform was used to obtain the partial derivatives of the VEH solution with respect to aquifer parameters needed for least squares method. The Levenberg method was used for parameter estimation to guarantee convergence. This procedure proved to be efficient and free of computational and convergence problems encountered when using real time solution.
Two approaches are used to represent the variable pressure history: the step pressure SP and the linear pressure LP methods.The two approaches are used to generated water influx data and the values obtained by both methods are compared with the actual (assumed) data. The LP method is found to yield more accurate results and is used in the parameter estimation algorithm.
The developed algorithm can be applied for performance prediction of oil and gas reservoirs under water drive and for the simultaneous estimation of original hydrocarbons in place (OHIP) and aquifer parameters based on material balance equations.
The Coefficient of Isothermal Compressibility of Black Oils
Authors: Al-Marhoun Muhammad Ali 
Published: December 2007

Abstract
This paper presents a new correlation for the coefficient of isothermal compressibility of black oils at pressures above the bubble point. The correlation is expressed as an empirical function of oil relative density at bubble point pressure, reservoir temperature, bubble point pressure and the reservoir pressure. A total of 3412 data points from 186 laboratory PVT analyses from Middle East fields were used to develop the oil compressibility correlation. The data encompassed a wide range of gas-oil ratios, oil and gas relative densities, reservoir pressure, and reservoir temperature.
Multiple linear and nonlinear regressions were used to develop this model. This model is chosen from large number of models tested. The evaluation of the correlation includes comparative studies of the new and existing mathematical models of oil compressibility correlation.
The model is validated by using three different data sets from other geographical region of the world not used in the development of the model.
The newly developed mathematical model and correlation outperforms the existing mathematical models and correlations for oil compressibility based on low value of average absolute percent relative error and standard deviation.
A Probability Approach to Development of a Large Carbonate Reservoir with Natural Fractures and Stratiform Super-Permeabilities
Authors: Pham T. R. , Stenger B. A. , Al-Otaibi U. F. , Al-Afaleg N. I. , Al-Ali Z. A. , Sarda S. 
Published: December 2007

Abstract
This paper describes a development strategy with peripheral water flood for Haradh Arab-D reservoir, a large oil bearing carbonate part of the greater Ghawar field. In a heterogeneous matrix permeability background, geological discontinuities such as faults, fractures, and stratiform high permeability streaks lead to a decisional divergence between development options. In this regard, optimizing the field development plan aims to find a proper balance among several conflicting requirements.
In the case of Haradh Arab-D, the field development options are divided into two components. The first component is a development scheme that is the most cost effective with respect to production plateau, oil recovery and reservoir conformance. This option involves a multi-disciplinary team addressing the development challenges by extracting information from nearby development experience, quantifying uncertainty with deterministic and stochastic modeling techniques. An array of different reservoir simulation models (Single media full field model, Dual-porosity-permeability model, Local grid refinement model, and Streamline model) was used for the purpose (1). This results in a preliminary development plan with the application of the horizontal well options with respect to well placement, horizontal direction, completion interval selection and the length of the horizontal section.
The second component, the focus of this paper, is the sensitivity analysis and risk assessment running concurrently with reservoir simulation to develop a Pareto chart for different reservoir parameters such as Fracture density and connectivity, Super-permeability layers, Skin damage, Aquifer size, and Kv/Kh ratio. The most sensitive parameters with respect to oil recovery are identified for re-assessment and further improvement and optimization of the development plan. Data acquisition program, reservoir performance evaluation and production injection strategies are conducted with these sensitivities in mind. They are executed with the highest priorities given to the most sensitive parameters.
In order to ensure that the target objective is achievable, wells drilled during the initial development phase are tested to validate the development strategy. Monte Carlo simulations again are run on periodic basis with actual field data input to further optimize the development.
Identification of High Residual Gas Saturation Zone and Evaluation of its Impact on the Development of the Central-C Gas Condensate Field- Oman
Authors: Al-Kindi Azhar , Al-Shammakhi Khamis 
Published: December 2007

Abstract
The active government gas exploration programme in Oman has recently added another sizeable gas-condensate discovery that was drilled and tested by Central-C-1. Destined to unlock the first CA sandstone gas-condensate field, the well results indicated a very prolific reservoir.
In the process of data gathering, a number of challenging aspects were identified and assessed. Residual gas saturation is the most interesting and potentially high impacting aspect. This paper addresses variations on the gas saturation profile as calculated from the petrophysical logs, the identification from the special core analysis measurement of high residual gas saturation rocks, and all relevant findings inferred from the production testing and the static pressure gradient measurement.
Despite cautioned applicability of the SCAL measurement results to reservoir conditions, a potential evidence for part of the CA reservoir accommodating high residual gas saturation was recorded. Number of scenarios were modelled to assess the impact of high residual gas saturation in relation with other reservoir uncertainties normally associated with exploration reserve bookings.
These scenarios ultimately studied the impact of the residual gas saturation uncertainty on the development economics of the field. This paper explains why major economic measures, such as gas and the condensate recovery efficiencies, well placements and aquifer influx were seen sensitive to this uncertainty.
For a comprehensive evaluation of its impact, a relationship between rock properties distribution and residual gas saturation was invisaged as a comprehensive evaluation method. In a deeper concept this translates into a relationship between the interpreted original depositional model and the adopted charge model. This interesting relationship was evaluated in the simulator using a special saturation-porosity dependence that was primarily based on the SCAL measurements.
This paper details the analytical and the numerical approach used to evaluate the impact of the uncertainty in residual gas saturation. It highlights how this uncertainty features within the appraisal data gathering targets and within the surveillance strategy of this field.
Integrated Development Approach For A Mature Oil Field
Authors: Murty Challa R. K. , Al-Haddad Abdulla 
Published: December 2007

Abstract
Bahrain field, discovered in 1932, is a highly faulted asymmetrical anticline trending in North - South direction (Fig. 1). There are as many as seventeen oil producing and three gas producing reservoirs within Jurassic to upper Cretaceous formations apart from the Khuff gas zones below in Permian limestone formations (Fig-2). These reservoirs occur with divergent lithology, rock and fluid properties. Some of them are saturated while some are highly under saturated. Some of them are oil wet and some water wet. They operate under various drive mechanisms and pressure maintenance schemes. Gas injection in Mauddud, which is one of the major oil producing zones in Bahrain field, has been in operation for the last 65 years. Gas injection in Arab-D is in progress from 1986. Pilot peripheral water injection is in progress in wara sands in NE area of the field since 1995. Additionally, different production mechanisms like gas lift, pumping and stop cocking for GOR control is applied. The field being mature and structurally complicated naturally demands an integrated approach for effective reservoir management to ensure maximum recovery. Due to application of diverse reservoir management techniques, reservoir characterization, Geo statistical application for anisotropy and increased accuracy for simulation, the field has been producing with minimum annual decline (Fig-3). By integrating the Geological, Seismic and reservoir / production data the productive limits of various reservoirs have been extended adding substantial reserves. This paper briefly discusses the approach adopted in the effective reservoir management of this giant mature oil field.