bluuebunny/crossref_metadata_2025_split huggingface dataset:
Advanced Technology for Rapid Minimum Miscibility Pressure Determination (Part 1)
Authors: Adyani Wan Razak Wan Nurul , Kechut Nor Idah 
Published: December 2007

Abstract
A prototype apparatus integrating a state-of-the-art micro-slim tube (MST) was developed and tested for rapid determination of Minimum Miscibility Pressure (MMP). The equipment, GEMA (Gas Extraction & Miscibility Analyser), uses an advanced technology of data acquisition and control system, making it a reliable tool for rapid MMP determination. MST is an unpacked, coiled stainless steel column of 30 m long and 0.32 mm ID. The small bore capillary column permits a high linear displacement rate resulting in a much shorter time needed per test of only 2 to 3 hours (including cleaning) as compared to 2-3 days if the conventional slim tube apparatus is used. The relatively small height-equivalent-to-a-theoretical-plate (HETP) in a capillary column ensures thousands of multiple contacts between the injected gas and oil, which cannot be practically achieved in the conventional slim tube. With this newly upgraded equipment, MMP determination for one sample takes only 2-3 days to complete as opposed to 2-3 weeks with the normal slim tube.
The method has been tested for various Malaysian reservoir fluid samples and the MMP results obtained are consistent with values estimated using published correlations such as Johnson & Pollin (1981), Glaso (1985) and Cronquist (1978). The equipment is proven to be very reliable to determine the MMP.
An Investigation of Near-Wellbore Flow Properties Using Sonic Scanner Measurements and Interval Pressure Transient Testing
Authors: Ayan Cosan , Petricola Mario , Knight Philip , Lalanne Bruno 
Published: December 2007

Abstract
Wireline Formation Tester (WFT) pretest success ratio (good versus tight pressure points) has been traditionally low in East Kalimantan-Indonesia over decades despite technological advances. One possible reason has been postulated as alteration of near-wellbore formation properties during drilling operations. The relatively tight gas sands are drilled with significant overbalance due to a mix of depleted and virgin zone layers using oil based mud systems. To further investigate possible near formation alteration, an extensive evaluation program was undertaken, using new generation sonic logs, WFT-multi-probe interval pressure transient testing (IPTT) and coring.
A Sonic Scanner* survey was conducted in Tunu field to investigate possible nearby formation alteration, followed by MDT*-multi-probe IPTT. The Sonic Scanner dipole radial profiling showed some radial property change at several zones. The altered zone radial extent was quantified. The MDT-IPTT tests quantified the, virgin zone effective gas permeability and permeability anisotropy as well as gave a fair idea of the open hole skin factor. Combination of the results gave altered zone radius, altered zone permeability, virgin zone permeability and anisotropy on a comparative basis between different zones. Moreover, the results from both dipole radial profiling and MDT-IPTT indicated that formation alteration not necessarily increases with overbalance. The results quantified nearby formation alteration, showed this as a possibility and can further help in selecting the best perforation strategy.
Gas Coning Control for Smart Wells
Authors: Leemhuis A. P. , Belfroid S. P. C , Alberts G. J. N. 
Published: December 2007

Abstract
A strong increase in gas influx due to gas coning and the resulting bean-back because of Gas to Oil Ratio (GOR) constraints can severely limit oil production and reservoir drive energy. The purpose of this paper is to demonstrate that oil production after a gas breakthrough can be optimized by means of an inflow control strategy that takes the effects of ‘natural gas lift’ and production choking into account. Within the research framework of the "Integrated System Approach Petroleum Production" (ISAPP) knowledge center of TNO, TU Delft and Shell, it has been shown that this optimization can be achieved by controlling the location and amount of gas influx in a horizontal smart well.
In order to show a proof of principle we have implemented a PID feedback controller, which controls the gas fraction in a well by changing its Inflow Control Valve (ICV) settings, on a test case in a dynamic reservoir simulator. We introduce a three step strategy for production optimization: firstly we model how the controlled production rate after breakthrough depends on the gas fraction; secondly we will determine the optimal gas fraction; thirdly we will consider the capability of a PID controller to produce at this optimal gas fraction.
Simulation experiments show that a PID controller is an effective means to prevent a full gas breakthrough and, moreover, can be used to increase the produced oil rate by tuning ICV settings to an optimal gas fraction. These experiments also demonstrate the benefits of using downhole ICV control in comparison to wellhead control.
In current operations ICVs are mostly used to completely shut down well segments that experience gas coning. We show that by keeping these ICVs open in a controlled way the, otherwise undesirable, phenomenon of gas coning can be used to optimize oil production.
Inverted Venturi: Optimising Recovery Through Flow Measurement
Authors: Ong J. Tim , Aymond Michael , Albarado Tesia , Majid Javid , Daniels Paula , Jordy Dustin , Lafleur Louis 
Published: December 2007

Abstract
The advent of high crude oil prices and mature fields has seen a rush for efficient recovery methods. This has spurred the development of "monitor-feedback-control" systems through intelligent well system (IWS) and interventional processes. Traditionally, downhole permanent flow measurement is performed using differential pressure meters; e.g. venturi. The intrusive nature of these flowmeters prevents easy access for interventional processes and creates a loss in well lift.
The main aim of an inverted venturi design is to allow full bore access whilst maintaining the downhole measurement accuracy requirements. The flowmeter has a reverse mechanical design compared to a restrictive venturi. Instead of a constricted section in the tubing, the inverted venturi has an expanded section. The theoretical principles are still based around simple energy and momentum conservation. Due to these facts, the operation of the tool requires the use of a pair of high resolution pressure gauge. The main breakthrough came from the development of a high resolution pressure transducer.
Surface testing of the flowmeter has demonstrated flow measurement uncertainty better than 8% for instantaneous flow rate measurement and better than 1.5% in bulk flow rate measurement. These flowmeters have also been deployed successfully in the field. Installation of these flowmeters in the Gulf of Mexico (GOM) region has shown a similar level of accuracies and has provided immense value to production. Apart from providing full bore access, the flowmeter is more robust as it is able to withstand higher gas volume presence in production rather than that of restrictive venturi. Due to the sensitivity of the pressure transducer, the flowmeter is also able to detect the presence of gas in production which adds value to the recovery process.
Installations are planned in the near future in IWS applications. These will include applications for multi-zone allocation flowmeters, injection flowmeters for both gas and water applications and commingled flow production meters. The application for the inverted venturi is limitless as it is not constrained by the typically issues surrounding restrictive venturi such as the loss of wellbore access and well lift.
Uniquely Characteristics Mixed-Metal Oxide (MMO) Fluid Cure Lost Circulation While Meeting European Environmental Regulations
Authors: Oswald Reinhard , Marinescu Pavel , Vlasceanu Paulin 
Published: December 2007

Abstract
Even though "New Technology" has become the catch phrase in today's drilling industry, downhole losses still account for an important part of well costs overruns worldwide. Losses not only increase the mud bill but also to a significant extent affect the total project cost and results, through rig downtime, multiple cementing operations or other alternative solutions attempts. The risk of the operations that encounter total loss of circulation is also increased, which require alternative costly solutions. In addition, the continuous demand for improved drilling performance, safety and environmental compliance and highly targeted production rates magnify the challenges.
This paper addresses the application of uniquely engineered fluid and the results of a drilling campaign in traditionally total lost circulation problematic fields by a major operator in Romania. The system used is the latest generation of Mixed-Metal Oxide (MMO) products, a water-based fluid system with outstanding solids suspension properties, but very high shear-thinning, that still screens easily even at high flow rates and through fine screens. It contains no components that can harm the environment, so the waste generated could be categorized as EWC (European Waste Code) 01 05 04 &lt;fresh water drilling mud and waste&gt; according to the European waste regulations.
In this campaign, the system was used in several wells where previously total loss circulation, multiple cement plugs, and lengthy drilling breaks were common. The authors detail the successful implementation and continuous improvement of the system in nine wells where it eliminated or dramatically reduced losses so valuable rig time was saved while eliminating multiple trips and time consuming cementing attempts. During the campaign, increased inhibition was deemed advantageous to drill through shale formations in the same interval with thief zones, so newest research and development products were introduced. Extensive laboratory and field tests results are also included, together with field results.
Reservoir Characterization and Modelling of Stacked Fluvial/Shallow Marine Reservoirs: What is Important for Fluid-Flow Performance and Effective Reservoir Prediction?
Authors: Samantray Ajay , Kraaijveld Martin , Hognestad Jon , Bulushi Waleed 
Published: December 2007

Abstract
Earth modelling and field implementation experience in fluvial/shallow marine clastic reservoirs suggests that relatively large, km to m scale geologic features such as stratal framework and facies architecture dominate the model behaviour and influence the accuracy of performance forecast more than numerically driven pore scale heterogeneity.
Twenty seven reservoir models were built by using different modelling methods and varying a combination of more uncertain reservoir characterization parameters ranging in scale from field to voxel to pore level. The models were largely influenced by deterministic geological controls rather than numerically driven stochastic variations. Guided by regional work, core and image log integration, the large scale stratal framework, the facies scheme and the zonal variograms were kept the same in all the models while the rock fabric and pore scale heterogeneity were varied using facies models, reservoir trend maps, and permeability contrast scenarios. These 27 models were all subjected to history match constrained fluid-flow simulation with a partially active aquifer, and peripheral and pattern waterflooding. Static and dynamic parameter uncertainties were handled by using experimental design.
The results show that oil recovery from existing wells at 98% water cut ranges from 25 to 40% in these 27 models. Also, there are differences (greater than 20%) in water-breakthrough time, water cut, and cumulative water production. While the large scale stratal framework defined the flow units and provided fundamental control on zonal production behaviour (e.g. differential depletion, early water breakthrough, and conformance control), the differences in oil recoveries and water cut among all models were found to be related to variation in m- scale rock heterogeneity rather than pore scale heterogeneity and permeability contrast.
Do we need more complex, numerically exhaustive models to predict flow performance in channelised reservoirs with reasonable well control? Some of the simple, but geologically constrained models we constructed provided superior flow-simulation results, impacted development concepts and led to accurate prognosis from new drills.
Case History: Application of Coiled Tubing Tractor to Acid Stimulate Open Hole Extended Reach Power Water Injector Well
Authors: Al Shehri Ayedh M. , Al-Driweesh Saad M. , Al Omari Mazen , Al Sarakbi Samir 
Published: December 2007

Abstract
With the increasing complexity of well completion, the rigless intervention work is becoming more challenging. Conventional techniques are no more adequate to access long horizontal wells to perform intervention work such as acid stimulation, logging, and zonal isolation.
This paper will describe the process of using a downhole coiled tubing (CT) tractor to access a horizontal open hole (OH) extended reach power water injector (PWI) well in the Ghawar field, the world's largest oil field, to perform a huge matrix acid stimulation job. The volume of the treatment is considered one of the largest for a PWI and the first utilization of a CT tractor in the Ghawar field. The paper will review the process of candidate selection, job design and planning, execution, and results and post job evaluation. The job set an excellent example of advancement in intervention technique accessing long horizontal wells beyond the normal reach of coiled tubing. In this job, the CT tractor has increased the reach of CT by 54% and a world record of coiled tubing tractored interval in horizontal OH of more than 5,000 ft was achieved. The injection rate of the stimulated wells was increased by more than twofold.
New Method for Supercharging Estimation
Authors: Wu Jianghui , Meister Matthias , Li Baoyan 
Published: December 2007

Abstract
Formation testers are used to measure formation pressures at discrete depths to determine pressure gradients for zones of interest. The gradients are used to identify fluid types, to estimate the level of pressure depletion, and to check connectivity between different zones. Pressure supercharging is often observed during formation testing while drilling or wireline formation testing, especially when the permeability of the formation is low. The pressure measurement is greatly affected by supercharging, and accurate initial formation pressure can not be obtained directly.
In order for the supercharged pressures to be used for reservoir management purposes, the amount of supercharging has to be estimated and subtracted from the measured pressures. We present a single-phase invasion model which couples a mudcake growth model with an analytical formation fluid-flow model. Supercharging is a function of mudcake quality, pressure overbalance, and properties of fluid and formation. In a while-drilling operation, the time exposed to the overbalance is also a factor. Inversion is conducted to fit the invasion model with pressure measurements. The inverted five model parameters include initial formation pressure, compaction factor, mudcake permeability, mudcake thickness (at an arbitrary time before the testing), and skin (internal mudcake). The non-uniqueness of the inversion result is quantified with a statistical method that uses a Monte Carlo sampling method.
In addition to the statistical method, a deterministic method is developed to estimate initial formation pressure. This method assumes that flow resistance of mudcake grows at a constant rate during the test interval. Initial pressure and growth rate are calculated deterministically from at least three pressure measurements. Field cases are presented to demonstrate the robustness of both statistical and deterministic methods. The estimated initial formation pressure has good agreement with time-lapse LWD pressure measurements.
In this paper, a more accurate analytical formation fluid- flow model was used instead of line-source approximation. The internal mudcake is represented by the skin factor in the analytical model. The coupled invasion model has five parameters. While the previous seven-parameter model requires two sets of pressure measurement under two different hydrostatic pressures, the new model can be applied without the practical limits, it needs only one set of pressure measurements.
High-Angle Well Deliverability Modeling for Openhole Gravel-Pack Completion Under Ultrahigh Gas Rate
Authors: Tang Yula , (Bill) Huang W. S. 
Published: December 2007

AbstractOpen-hole Gravel packing is increasingly becoming a standard practice in the deep-water, subsea completion environment. A Chevron offshore gas reservoir will be developed with highangle near-horizontal wells with openhole gravel packs completion (OHGP) for its first phase development. The ultra high rate for individual well could be up to 320 MMSCFD and the non-Darcy effect is too significant to overlook. The objective of this investigation is to build an accurate model, to validate and quantify the non-Darcy, mechanical skins for the high-angle OHGP gas wells, and finally to develop a recommendation for the optimized design.A comprehensive semi-analytical model was developed based on modification of the horizontal well model. The additional pressure drop is added to consider the mechanical skin and non-Darcy flow in the near-wellbore zones of drilling damage, mud-cake, gravel packs, and the sand screen.This investigation indicates that the non-Darcy effect could significantly affect the production rate and the economics of the project. It was found that 80° wells have a 35% average reduction in PI due to skin and non-Darcy effect. The PI for 60° wells reduces by 62% comparing to the 80° wells due to concentrated flow to a much shorter wellbore and much larger scaled skin and non-Darcy term. Uncertainty analysis was performed on non-Darcy beta-factor, formation damage parameters, and gas effective permeability.Wellbore open-to-flow area and hydraulics affect the high rate gas well's performance significantly. The preferred design is an OHGP slanted well at 80 degrees without shunt tube (6.366" ID), which can yield much higher PI than the base design. The sound engineering design of the well completion would allow us to deliver superior value through this huge gas property.
Using Production Logs to Calibrate Horizontal Wells in Reservoir Simulation
Authors: Wang Y. , Moreno J. , Harfoushian J. H. 
Published: December 2007

AbstractHorizontal wells often present a substantial challenge in reservoir simulation. In a recent field review, we experienced difficulties modeling long horizontal wells due to the combined complexity of the wells and the reservoir. This reservoir is located in an offshore field that produces oil from a relatively thin oil rim. The reservoir also contains a large gas cap that provides the dominant energy for reservoir recovery. The reservoir is composed of interbedded, shallow marine-ridge sands with some coarsening-up sequences.A typical horizontal well in this field has perforation intervals of about 1,200–2,900 ft, penetrating depositional sequences from the bottom up, and produces from multiple formations. Wells are placed close to the oil-water contact, sufficiently far from the gas-oil contact to reduce the effects of gas coning and channeling.Due to the large heterogeneity of reservoir properties in different layers, complexity of the geological feature, and the dynamics within the horizontal wellbore, it is very challenging to reproduce the actual production profile in the simulation model. For example, an unfavorable combination of a sump (variation in depth) in the well trajectory and fluid holdups may prevent the toe from producing. The dynamics are difficult to capture without direct production logging and the use of special options of the simulator.In this study, appropriate technologies were applied to solve this problem. Production logging was implemented on four wells. The results revealed that some perforation intervals do not contribute to production. It also exposed allocation problems in the historical production data. This information was used to validate the performance of some wells and to calibrate other wells that exhibit different production profiles. Some simulator options such as multi-segment wells and PLT reporting have been applied to facilitate this calibration process. With this calibration, history matching becomes a more guided process, and the resulting model is more consistent with the actual performance, thus, enhancing its predictive power.This paper describes certain special wellbore dynamic behaviors that have not been covered in the literature. It illustrates the challenges of simulating horizontal wells and how production logging is used to resolve the problem and calibrate the model for better predictive power.
Irong Barat Field Development: An Integrated Approach to Maximize Asset Value
Authors: Ghapor Zamri Abdul , Kuang Lim Hock 
Published: December 2007

Abstract
The Irong Barat field, located offshore Peninsular Malaysia, has been producing since 1984 from the Irong Barat A (IBA) platform. Production in the field, which is complexly faulted with major and minor faults dividing the field into four major fault-block compartments, is primarily from the Group H channelized facies reservoirs. The increased complexity in structural interpretation and reservoir mapping as a result of the complex faulting posed a challenge in managing risks and uncertainties in developing and maximizing value of this field.
Upon successful initial development of the primary fault block, additional data was acquired to mature further opportunities resulting in additional field development at Irong Barat, particularly the IBA Redevelopment, and the Irong Barat B and Irong Barat C developments. Integration of reservoir surveillance/studies, geological and geophysical analysis, facilities and drilling technologies was applied by Irong Barat Teams to mitigate the risks and uncertainties of the identified development opportunities. As a result of this effort, over the last six years crude production has increased from ten to 25 thousand barrels of oil per day and developable reserves have grown by about 50 million barrels.
This paper describes the integration of key technologies and approach taken to manage the risks and uncertainties in these projects to increase the Irong Barat field value.