bluuebunny/crossref_metadata_2025 huggingface dataset:
Analytical and Numerical Investigation of Multicomponent Multiphase WAG Displacements
Authors: LaForce Tara , Jessen Kristian
Published: December 2007

In this paper we study the ability of analytical solutions for four-component three-phase flow to predict displacement efficiency in water alternating gas (WAG) injection processes. We present equivalent analytical solutions for Riemann problems with injection compositions that are the average water and gas mixture for various WAG injection schemes. These solutions are compared to numerical calculations with variable slug sizes and used to explore the effect of slug size, injecting water versus gas first, and the average injection composition on displacement efficiency in compositional WAG schemes.

We model immiscible WAG injection of water and CO2 into an oil reservoir containing C10 and CH4 with and without a mobile aqueous phase present initially. These are the first analytical solutions for three-phase initial conditions in quaternary systems. The magnitude of the oil bank and the breakthrough time of the injected fluids are accurately predicted by the analytical solutions, even for displacements where large water and gas slugs are injected. As slug size decreases, the displacements predicted by numerical calculations converge to the analytical solutions.

The sequence of shocks in composition predicted by the analytical solutions is observed in WAG injection simulations for relatively large slugs, regardless of the injection sequence. The WAG simulations appear as if oscillations in the profiles are super-imposed on top of the sequence of rarefaction and shock waves predicted by analytical solutions. The trailing end of the water and gas profiles are sensitive to whether water or gas is injected first. However, the injection sequence and slug size has little impact on the bank of heavy hydrocarbon, even at the trailing end of the displacement.
An Investigation Into the Need of a Dynamic Coupled Well-Reservoir Simulator
Authors: Nennie E. D. , Alberts G. J. N. , Belfroid S. P. C. , Peters E. , Joosten G. J. P.
Published: December 2007

Within the research framework of the "Integrated System Approach Petroleum Production" (ISAPP) knowledge center of TNO, TU Delft and Shell, the necessity of taking the interaction between dynamic reservoir and dynamic well behavior into account when optimizing a producing asset is investigated. To simulate dynamic phenomena in the well and in the reservoir, a dynamic multiphase well simulation tool (OLGA) and a dynamic multiphase reservoir simulator (MoReS) have been used. Both simulators have been coupled using an explicit scheme.

The dynamic well simulator, the dynamic reservoir simulator and the coupled dynamic well-reservoir simulator have been used to simulate a realistic test case which consists of a horizontal well with three inflow sections located in a thin oil rim. A number of scenarios are investigated that play a crucial role during different stages of the well's lifetime: naturally occurring phenomena, e.g. coning, and production dynamics, e.g. shut-in.

The results of dynamic well simulations, dynamic reservoir simulations and coupled well-reservoir simulations are presented and an overview is given of the cases where the results of the coupled simulations are significantly more accurate in comparison to stand-alone well or reservoir simulations. For gas coning it is shown that the coupled simulator has much faster pressure transients after gas breakthrough than the dynamic reservoir simulator. Therefore, the coupled well-reservoir simulator should be used to simulate gas breakthrough and to optimize production using gas coning control. For small time scale phenomena, order of less then one day, the well and reservoir transients overlap. Simulations show that the coupled simulator is essential for an accurate prediction of the well-reservoir interaction during these small time scale phenomena.
Automatic Surveillance System for Large Gas Fields with Multifrequency Measurements
Authors: Mota M. , Campos O. M. , Escalona H. , Teran L. D. , Sandoval G.
Published: December 2007

This paper presents the results of an automatic surveillance system implemented by PEMEX for one of Mexico's largest gas fields. Activo Integral Burgos (AIB) is a typical example of large gas field where production declined due to gas-loading backpressure and reduced permeability in the target formation. The fast decline of the gas wells during their first year of production drove a change from reactive into proactive management tactic to monitor the field and to select candidates for workovers. However, the large number of wells in AIB (approximately 2000 active wells) and the fact 95% of data is manually captured made the implementation of automatic surveillance particularly challenging.

We introduced an automatic surveillance solution that synchronizes the data collected daily in more than 200 wells. Conventional production tools, including Nodal modeling, Turner's equation, Decline Curve Analysis, or Pressure Survey, were individually validated and subsequently implemented as a sequence of automated routines to process the data over the entire field. The data was then analyzed using a self-organizing-map engine to automatically identify wells where fluid loading impedes production. Daily production rates were also computed using nodal models automatically updated with operational data for each well.

The integration of tasks including production data gathering and standardization, monitoring, reporting and alarm functionality, was a key element for the successful and efficient management of gas-loading problems at the field scale. Milestones achieved with this implementation included the automatic identification of problematic wells and a reconciliation of the production rates measured at the gathering stations with rates calculated at the well level.

This surveillance methodology offers new perspectives for the proactive management of wellbore liquid-loading problems in large fields with very limited data stream. The early-stage diagnosis of problems enables the operator to make decisions in record turn-around times and extends the productive life of the wells beyond initial expectations.
PC-SAFT Equation of State Applied to Petroleum Reservoir Fluids
Authors: Pedersen Karen Schou , Sørensen Casper Hadsbjerg
Published: December 2007

The PC-SAFT equation has been proposed as a potential next generation equation of state in the oil industry. It has already obtained widespread use for simulations on polymer systems, which shows that it has a capability of handling phase equilibria for systems with heavy hydrocarbons. A C7+ characterization procedure for use with the PC-SAFT equation has been developed and used to test how PC-SAFT performs on various types of petroleum reservoir fluids ranging from natural gas mixtures to heavy oils with asphaltenes. Promising results are seen for asphaltene onset pressures and for oil mixtures in general. With the currently published pure component parameters PC-SAFT is inferior to cubic equations of state for simulations on gas and gas condensate mixtures.
Water Injection Optimization for a Complex Fluvial Heavy-Oil Reservoir by Integrating Geological, Seismic, and Production Data
Authors: Feng Xin , Wen Xian-Huan , Li Bo , Liu Ming , Zhou Dengen , Ye Michael Q. , Hou Dongmei , Yang Qinghong , Lan Lichuan
Published: December 2007

BZ25-1s field in Bohai Bay, China is characterized as a complex fluvial channelized reservoir where small meandering channels (100-300m wide and 500 - >1000m long) were deposited at different geological times cross-cutting each other. There are many isolated small reservoir systems following channel distributions. Early production showed steep pressure and production decline. Quick implementation of water injection is needed to arrest the fast production decline and to stabilize reservoir pressure.

While designing the water injection plan, we faced a number of challenges, such as high mobility ratio (oil viscosity of ~200 cp), strong heterogeneity, poor reservoir connectivity, complex channel geometry, and irregular well patterns. A workflow integrating geological, well log, seismic and dynamic production data was developed to optimize water injection plan for this field.

Following the workflow, the optimal water injection design for platforms D and E areas was developed and quickly implemented within the first year of production. We started with a relatively small water injection rate and gradually increased the injection rate to avoid the fast water breakthrough and yet to limit the pressure decline rate. The responses from the water injection were very positive resulting in stable reservoir pressure and increase of oil production. Before water injection, the production decline rates were 30% and 50% for the wells in platforms D and E. After 1 year of water injection, oil production decline rates were reduced to 19% and 14%, respectively.

The responses of water injection for different well groups were analyzed in a timely fashion and adjustments to injection/production strategies were implemented accordingly. New information from the water injection response analysis was used to update the geological model to reduce the model uncertainty, as well as to adjust the water injection strategies for better sweep efficiency. Our experiences showed that such dynamic adjustment of injection and production schedule is very important to achieve better water injection efficiency for this heavy oil reservoir with complex channel geometry.
Success Stories in Onshore Production Surveillance and Optimization
Authors: Deaton David F. , Kloosterman John T.
Published: December 2007

This paper presents the assessment methodology, technology, data sources, workflows, critical factors and intermediate results of Marathon Oil Company's production surveillance solutions implemented within two major asset teams, Permian Basin and East Texas. It is represented as a model for operators implementing digital oilfields, i-fields, or automation to improve the surveillance aspect of their production operations. The paper presents an asset-based collaborative project process for needs assessment, a surveillance solution for linking and visualizing production data, a workflow definition process, and a mentoring approach on the solution and workflow to insure successful implementation and value realization.
Borehole Effects and Correction in OBM With Dip and Anisotropy for Triaxial Induction Tools
Authors: Wu P. , Wang H. , Minerbo G. , Homan D. , Barber T. , Frey M.
Published: December 2007

The latest advance in resistivity logging is the multi-spacing triaxial induction tool. In addition to the conventional induction logs, a triaxial induction tool provides added capability to measure formation anisotropy (horizontal and vertical resistivities), relative dip, and azimuthal angles over a wide range of logging conditions. The anisotropy measurement is very important in low-resistivity pay analysis, while the dip and azimuth measurements have many important geophysical and geological applications.

However, due to the physics of the triaxial induction measurements, the borehole effects are significant even for oil-base mud (OBM) conditions. These borehole effects must be corrected in order to obtain accurate measurements of the formation properties. Through extensive modeling studies, we learned that borehole effects depend on many parameters, including hole diameter, tool eccentric distance and azimuth, mud resistivity, formation horizontal and vertical resistivities, formation relative dip, and azimuth angles. Removing the borehole effects is a very difficult and complicated three dimensional (3D) electromagnetic inversion problem, which involves many free parameters.

We have developed an inversion algorithm for OBM filled boreholes that robustly solves for horizontal and vertical resistivities, relative dip and azimuth, tool eccentric distance and azimuth. The model for the inversion is an eccentric tool in a borehole through an anisotropic formation with a dip angle. These inverted parameters can then be used to derive the borehole correction for the triaxial measurements. We demonstrate the algorithm through theoretical examples and field logs. The algorithm is very efficient and fast enough to be implemented as real-time well site answer product.
Experimental Study of CO2 Injection into Saline Formations
Authors: Cinar Yildiray , Riaz Amir , Tchelepi Hamdi A.
Published: December 2007

We present experiments at the laboratory scale to investigate the influence of gravitational, viscous and capillary effects on the CO2 injection process. Two-dimensional experiments are performed in a vertical glass-bead pack, in the parameter range of practical flows, i.e. with Bond numbers of about 10-3, and capillary numbers of the order 10-4. Experiments are carried out primarily to demonstrate the type of flow regimes that occur under favorable as well as unfavorable conditions of density and viscosity. Experiments demonstrate the existence of pore scale instability in the presence of unfavorable gradients of viscosity and density, and as such, appear to be incapable of being modeled by conventional means. A comparison with estimates from percolation theory shows good agreement with experimental observations.
Horizontal Well Gravel Packing: Dynamic Alpha Wave Dune Height Calculation and Its Impact on Gravel Placement Job Execution
Authors: Chen Zhongming
Published: December 2007

Gravel packing long horizontal wells presents many challenges to completion operations. The accurate calculation of Alpha wave dune height under dynamic wellbore conditions is on the top of the list. Alpha wave dune height is critical during job planning and the afterward successful gravel placement execution. Excessive Alpha wave dune height is the cause of many early time screenout and job failures. The job parameters, including wellbore geometry, pump rate, leakoff and leakoff control, fluid density and viscosity, gravel particle size and geometry, liteProp and conventional gravel, wellbore temperature profile, bottomhole pressure distribution, will all have impact on Alpha wave height.

This paper investigates and summarizes several particle transfer models, analytical and empirical ones, their applications in Alpha wave dune height calculations, their limitations and effective application windows. The paper also provides dynamic Alpha wave height calculation methodology to account for dynamic bottomhole conditions, especially the fluid leakoff to formation and to screen wash pipe annulus, bottomhole in-situ gravel concentration, and their impact on Alpha wave dune height calculation. The sensitivities of these models under different job conditions are also studied.

Several job designs and application histories are presented in the paper to demonstrate the application of different particle transport models. Guidelines are provided for operators to make proper adjustment when an undesired condition is present during gravel placement.
Improving Well Productivity and Profitability in the Bakken—A Summary of Our Experiences Drilling, Stimulating, and Operating Horizontal Wells
Authors: Besler Monte R. , Steele John W. , Egan Tanner , Wagner Jed
Published: December 2007

This case study will summarize the lessons learned during the stimulation and operation of horizontal laterals completed in the Middle Bakken formation of North Dakota and Montana. This paper will compare the production histories of these wells to offset wells completed with other techniques to evaluate best industry practices. Insight will be shared as to the effect of lateral length, wellbore azimuth and stimulation design on well production and overall well economics.

The Bakken formation of the Williston Basin is undergoing significant development in Manitoba, Saskatchewan, Montana, and North Dakota. Numerous operators are active in the area, with a wide variety of development approaches. The industry has not yet reached consensus on optimal drilling and stimulation strategies.

Results indicate significant progress in improving well production, while reducing the drilled lateral length and the treatment size. Efforts to improve diversion and optimize proppant type and size appear to provide more effective fracture treatments, while eliminating production problems related to the flowback of frac sand.

This paper will provide the following benefits to readers: Operators in the Bakken have experienced significant problems with flowback of frac sand, requiring frequent pump changes, conservative production strategies, and expensive cleanouts prior to restimulation. This paper will describe the steps taken to eliminate proppant flowback into the wellbore and the estimated economic impact.This paper will provide a case study comparing the production from wells completed with a variety of strategies.The results suggest many current laterals drilled in the Bakken are ineffectively stimulated and demonstrate that significant increases in well profitability are possible with more optimized treatments.Optimizing fracture treatment designs for horizontal wells requires an estimation of the fracture geometry – particularly a description of the intersection between the wellbore and the fracture. A fracture treatment designed under the assumption of a longitudinal frac will be entirely inadequate if the actual fracture propagates in a transverse orientation. This paper will describe our understanding of the fracture geometry and how that has affected treatment designs.
Surge and Drag Analysis for Extended Reach Casing and Casing Flotation Operations With Centralizers: A Design Challenge?
Authors: Samuel G. Robello , Mason Colin J.
Published: December 2007

Refining advanced technologies for the successful completion of wells is paramount in high-risk, high-cost environments. Challenges are associated with complex well architectures and with the successful completion of wells deploying conventional or floated casing or liner strings. A key part of the design process is to be able predict both maximum downhole surge pressures and dynamic and static friction effects. The analysis also needs to take into account the impact of using centralizing devices. Understanding these effects during both casing running and reciprocation is important so that appropriate operational decisions can be made. Specific challenges are associated with running liners through casing strings or hole sections with limited annular clearance.

Centralizers are primarily installed on a casing string to provide adequate stand-off for primary cementing operations; however they are also sometimes used to aid in the deployment of casing strings. To achieve adequate stand-off, calculations are performed to determine the number of centralizers, their placement, and spacing frequency. Drag modeling is performed to ensure that the casing string will reach its target depth. This requires predictions of both static and dynamic drag effects that take into account the impact of centralizers and surge pressures on drag. In cases where non-rigid centralizers are used, conventional torque and drag models underestimate frictional drag effects. Similarly it is considered that steady state surge models under predict maximum surge pressures.

To address these concerns both improved models and comprehensive analysis is required. This paper describes the analytical models that are used to incorporate additional forces associated with centralizers. Both conventional and floated casing running scenarios, especially in close tolerance extended reach wells, are considered.
New Developments in Nucleation Theory and Their Impact on Natural Gas Separation
Authors: Kalikmanov Vitaly , Betting Marco , Bruining Johannes , Smeulders David
Published: December 2007

Conventional separators in the oil industry use a feed of oil and gas in two-phase multi-component equilibrium. Recently a new concept of separators has been introduced which can be fed with a single-phase gaseous mixture. The separator combines a quasi-isentropic expansion of the gas during which liquid droplets are formed by the nucleation process and a gas-liquid cyclonic separator. The performance predictions of such a separator depend critically on an adequate description of nucleation phenomena. For a large number of practical cases the Classical Nucleation Theory is very inaccurate. The recently proposed Mean-field Kinetic Nucleation Theory yields quantitatively accurate predictions of nucleation behavior of various microscopically diverse substances. An important advantage of non-equilibrium separation is the minimal use of chemicals and absence of regeneration systems, as opposed to conventional separation methods such as glycol contactors or silica gel towers.
Imposing Multiple Seismic Inversion Constraints on Reservoir Simulation Models
Authors: Kalla Subhash , White Christopher D. , Gunning James , Glinsky Michael E.
Published: December 2007

Well data reveal reservoir layering with relatively high vertical resolution but are areally sparse, whereas seismic data have low vertical resolution but are areally dense. Improved reservoir models can be constructed by integrating these data. The proposed method combines stochastic seismic inversion, finer-scale well data, and geologic continuity models to build ensembles of geomodels.

Stochastic seismic inversions operating at the mesoscale (≈10 m) generate rock property estimates that are consistent with regional rock physics and true-amplitude imaged seismic data. These can be used in a cascading workflow to generate ensembles of fine-scale reservoir models, wherein each realization from the Bayesian seismic inversion is treated as an exact constraint for an associated finer scale stochastic model. We use two-point statistical models for the fine-scale model, modeling thickness and porosity of multiple facies directly. The update of these fine-scale models by the seismic constraints yields highly correlated truncated Gaussian distributions. These generate potentially rich pinchout behavior and flexible spatial connectivities in the fine scale model.

The seismic constraints confine the fine-scale models to a posterior subspace corresponding to the constraint hypersur-face. A Markov Chain Monte Carlo samples the posterior distribution in this subspace using projection methods that exploit the reduced dimensionality that comes with the exact constraints.

These methods are demonstrated in three-dimensional flow simulations on a cornerpoint grid, illustrating the effects of stratigraphic variability on flow behavior.
Measurement and Calculation of Key Events During the Plunger Lift Cycle
Authors: Lea James F. , Rowlan O. L. , McCoy J. N.
Published: December 2007

As a normal gas well's production rate declines below a critical limit, produced liquids begin to collect in the tubing or flow passage, and the gas flow is further reduced or stopped by additional liquid pressure on the formation. Many authors describe the time when liquid begins to collect in the well as the gas flow has decreased below the critical flow rate, although perhaps more reliably, the production rate will begin to drop below the original decline curve. Popular lift methods for dealing with liquid loading caused by gas rates below critical are: compression, velocity strings, beam pumps and other pumps, surfactant injection, and plunger lift. Plunger lift is a popular method for dewatering gas wells due to the low initial installation cost and due to low operation cost by using the well's stored energy to dewater the well. Plunger lift is one of the primary artificial lift methods used to overcome liquid loading problems in gas wells.

A few simple rules-of-thumb are frequently used in the initial configuration of the plunger lift installation. These rules-of-thumb have been translated into mathematical algorithms to allow the operator to estimate the rise velocity of the plunger, the liquid slug size per cycle and time period intervals for the plunger cycle. Algorithms are used in this paper to calculate timings for events during the plunger lift cycle, and the times are compared to key events determined from measurements acquired at the well. For example, the minimum shut-in time calculated from one algorithm is compared to the precise time measured for the plunger to fall from the surface to the bottom of the well. Using the measured tubing and casing pressures and plunger location during the cycle along with other well parameters, the operator can verify the plunger lift system is operating as desired. Both measured plunger lift performance data and calculations from the algorithms guide the operator to effectively analyze, adjust and optimize the plunger lift installation. Acquired data from various plunger lifted wells are used to validate the algorithms presented.

Information presented in this paper will assist the operator of gas wells who is suffering from gas flow rates below critical and is using plunger lift to alleviate the corresponding liquid loading problem.
Stimulation Flowback Management: Keeping a Good Completion Good
Authors: Crafton James W. , Gunderson Dan
Published: December 2007

All oil and gas well stimulation processes, and particularly hydraulic fracturing, require a post-stimulation flow period to prepare the well for long-term production. Operators and service companies have begun to recognize this as one of the most critical times in the life of the well. Intensive management of the flowback and evaluation of the available performance information during flowback can yield significant improvement in the well's long-term performance. That information also provides the basis for improving future stimulation and well management strategies. For example, excessive flowback rates are known to cause proppant flowback or fracture collapse in a fracture stimulated well. Postponement of flowback after the stimulation and shut-ins once production is established do impact future performance.

Proper data collection and interpretation provide the ability to interpret the characteristics of the placed fracture and the impact and management of various flowback procedures. Specifically, it is possible to assess the conductivity of the proppant bed, its propagated length and the impact of on-set to multi-phase flow. If the flowback and data collection are properly conducted, the early data will also contain information about the characteristics of the reservoir and fracture. With this in mind, the types of data, acquisition and interpretation methods are shown for three field examples.
Reviving the Mature Handil Field: From Integrated Reservoir Study to Field Application
Authors: Herwin Henricus , Cassou Emmanuel , Yusuf Hotma
Published: December 2007

The Handil field, discovered in 1974, is a giant mature oilfield located in the Mahakam Delta, Indonesia. The field consists of 555 accumulations and was developed by more than 350 wells with conventional oil recovery methods: natural depletion and peripheral water injection. After many reservoirs have been water-flooded, in order to recover the tertiary oil, EOR lean gas injection project was started in November 1995 on five reservoirs. The project was successful and extended to the other six reservoirs in 2000. However, the field production continued to decline from 200,000 BOPD in the late seventies to 12,500 BOPD in 2003.

An integrated study on the largest EOR reservoir was performed to assess the projects' performance, including 3D geo-modeling, reservoir simulation and chemical tracer injection. The study permitted to track the main effects of the gas injection and define reservoir management guidelines for the other lean gas injection reservoirs.

In the same time, dynamic synthesis has been performed in all accumulation in Handil Field with objective to identify potential "by-passed" oil and un-drained areas. Following the study, an intensive Light Work Over campaign has been launched and three pilot wells, each with different completion type, have been successfully put on production and became the model for the next Handil development wells; horizontal well equipped by gas lift to recover viscous sandy reservoir in very shallow zone, gravel pack equipped by ESP to recover sandy reservoirs in shallow zone and monobore multi-target well equipped by gas lift to recover reservoirs in main zone.

The production has been increased by nearly 100 percents, from 12,500 BOPD in 2003 to 23,000 BOPD nowadays. Integrated reservoir study and the successful application of Light Work Over and Infill Well to recover "by-passed" oil and un-drained areas, supported by EOR techniques to maintain the reservoir pressure and sweep the tertiary oil, become the key elements to revive the mature Handil Field.
Formation Pressure while Drilling Utilized for Geosteering
Authors: Neumann P. M. , Salem K. M. , Tobert G. P. , Seifert D. J. , Dossary S. M. , Khaldi N. A. , Shokeir R. M.
Published: December 2007

Placement of a horizontal power water injector well in close proximity above an impermeable, undulating, heavy oil and tar layer poses a unique geosteering challenge. The uncertainty was to determine at what vertical depth fluid mobility stopped and heavy oil began in the high porosity reservoir. The heavy oil layer is undetectable with conventional real-time LWD measurements. Furthermore, new technology devices such as Formation Pressure While Drilling (FPWD) and NMR While Drilling can be used to detect heavy oil but only after the BHA has entered the layer. A technique of combining FPWD with LWD/MWD provides the best opportunity to identify and steer away from immobile layers, minimizing the risk of completing an injection well in intervals without injectivity.

The FPWD tool was placed behind the MWD/LWD assembly. LWD data was used to provide the information to locate ideal testing depths. This prevented taking "blind" pressure readings in low porosity/low permeability intervals during drilling operations. Conclusions from the pressure drawdown and build up profile, combined with pressure and mobility data, were used to make the decision whether to continue on the current well path or to consider a directional change.

Zones with limited injection potential were avoided after initial low mobility detection by the FPWD tools. Repeated "lost-seal" or "tight" readings from the FPWD tool in high porosity zones are excellent indicators that the bottom hole assembly has entered an impermeable layer in a highly porous reservoir. Timely communication of low-to-no mobility readings generated the opportunity to geosteer the well back into permeable reservoir to meet the well placement objectives.

This paper covers two case studies demonstrating both entry into and steering away from impermeable heavy oil layers in addition to discussions on the planning and geosteering operations.
Operation Support Centers - Real Time Drilling Optimization and Risk Mitigation
Authors: Monden Takashi , Chia Christopher R.
Published: December 2007

Real time connectivity from the rig to the office is becoming the norm for many operations today. The real time operation support center (OSC) is the hub of these activities in town where domain experts, data interpretation experts, and drilling experts alike can be involved directly in data-centric collaboration and critical decision making. Having the ability to move the point of decision making from the point of data acquisition to the OSC intuitively provides the capability for more effective drilling optimization and the direct saving of non-productive time through risk mitigation.

A series of real case studies that show the range and scale of measures, and the interpretive actions that can be taken to optimize drilling and minimize downtime. Direct improvements in drilling rate of penetration through advanced software modeling of drilling parameters will be shown. These cases involve both the reduction of shock and vibration to the drilling assembly, thereby transmitting more of the energy in the system to the bit face, as well as the direct rate of penetration improvements through balancing weight on bit and surface RPM for each drilling system. Other cases will demonstrate improved well placement in the reservoir through the combination of monitoring the drilling parameters in conjunction with the real time data from the formation evaluation downhole tools. Direct troubleshooting of downhole tool problems relating to changes in downhole conditions will also be presented, and in many cases this can save an unnecessary trip out of hole.

Together, these case studies will show that significant value can be achieved by maximizing the effectiveness of the OSC, and by fully integrating real time quality and decision making procedures into all drilling operations. It can further be concluded from these case studies that this value can be measured, and can truly create a step change in performance. These improvements can be translated directly into lower cost per foot, and better hole quality, in addition to reduced lost in hole and therefore better equipment utilization.
Improving Local Bentonite Performance for Drilling Fluids Applications
Authors: Al-Homadhi Emad S.
Published: December 2007

Drilling fluid is a vital element of the drilling process. Any drilling fluid must have common properties that facilitate safe and satisfactory completion of the well.

The main component of water base mud is clay (mostly bentonite). The present consumption of bentonite clay in the drilling operations in Saudi Arabia alone can reach over 100 thousands tons a year and all of it is imported from USA. This trend is expected to continue as drilling activity increases. The large consumption and the high importation cost of this material lead to an attempt to find a local substitute.

Clays in Saudi Arabia are represented by numerous commercial stocks. The use of these local clays in the drilling activities can save a huge amount of hard currency that otherwise would be spent on importing it from abroad.

Several attempts were made to investigate shale outcrop precipitates in the kingdom. This work focuses on the possibility of the utilization of local bentonite clay minerals as a basic material for drilling fluids used to drill oil and gas wells. The only known bentonite outcrop in the kingdom is in Khulays area, 70 km north Jeddah adjacent to Makkah-Madinah road.

API specifications for acceptable drilling mud was the base for evaluating the local bentonite The properties of the local mud can be improved economically by adding some cheep materials to the prepared mud to enhance its viscosity and filtration loss (such as CMC, Drispac polymer, and bentonite extenders). Also shearing speed can be used as an enhancement method to improve the dispersion rate of the clay suspension, and hence increase viscosity and decrease filtration loss. But the used shearing speed should be limited to a practical and economical speed.

The bentonite extender can be either a salt or a polymer, it enhances viscosity buildup by slightly flocculating the bentonite suspension. Sodium carbonate is an example of a salt that can be added as an extender. Soaking raw bentonite with a solution of sodium salt resulted, through ion exchange, in a higher sodium bentonite content. More effective extenders than inorganic salts are the high molecular weight linear polymers.
Pore Network Modeling: A New Technology for SCAL Predictions and Interpretations
Authors: Suicmez V. S. , Touati M.
Published: December 2007

There have been recently substantial advances in Pore Scale Physics Discipline. These advances can now be used for the benefit of special core analysis (SCAL) measurements and interpretations. This paper is devoted to explain these improvements from two perspectives: (i) Pore scale imaging and network extraction (ii) Fluid flow modeling applied on the extracted networks in order to predict some key petrophysical properties (capillary pressures, relative permeabilities).

We use either thin sections or X-ray microtomograhy (micro-CT) to analyze rock cuttings of sandstones from Saudi Arabian oil and gas fields. These cuttings are a few mm across and are imaged with a resolution of 3 to 12 microns. Hence, the details of the three-dimensional pore space can be clearly seen. A maximal ball algorithm1,2 is used to extract a topologically equivalent pore-throat network: the largest inscribed spheres in the pore space representing the pores, with throats representing the connections between them.

In parallel to this algorithm, thin section images are utilized to build 3D equivalent images, reproducing porosity by a similar spatial variation of the grain sizes obtained from the thin sections. This has been done through the so called process based technique3 which is based on honoring the geological depositional mode of the rock.

The final aim is to input these network models into porescale fluid flow simulators to predict macroscopic properties such as relative permeability and capillary pressure. Blind tests are envisaged to compare the measured petrophysical properties and their corresponding numerical estimations.

This acts as a valuable complement to special core analysis, enabling predictions of properties – such as three phase relative permeabilities and the impact of wettability trends − outside the range probed experimentally.
A New Hybrid Inverse Modeling Method for Water Quality Monitoring Using Remotely Sensed Data
Authors: Shahraiyni H. Taheri , Schaale M. , Shouraki S. Bagheri , Fell F. , Fischer J. , Taheri M. , Preusker R. , Tajrishy M. , Vatandoust M. , Shahraeini M. Taheri , Sani P. Navi , Taherishahraini Z. , Khodaparast H.
Published: December 2007

All of the man-made objects and anthropogenic activities related to the oil industries in water bodies (e.g. drilling, equipment installation, construction of oil platforms and especially oil spillages) have environmental impacts on water ecosystems. The assessment of oil field operations and oil platforms impacts on water quality have become a necessity throughout the world. Phytoplanktons have the lowest trophic level in water environment; therefore the life of all of the other marine animals is highly relevant to phytoplanktonic population. Hence it seems necessary to monitor the spatiotemporal effects of different activities and events, related to oil industries on phytoplanktons. Chlorophyll is an indicator of phytoplanktonic biomass. Area-wide monitoring of Chlorophyll using conventional in-situ measurement methods is expensive and time consuming. However remote sensing measurements can provide a complementary tool for chlorophyll monitoring, but the remotely sensed data inherently contain high level of noise and some of the methods are failed in operational application to satellite data for the chlorophyll retrieval and also it is not easy to retrieve chlorophyll of noisy remotely sensed data in optically complex waters. Therefore robust and accurate inverse modeling methods for the chlorophyll retrieval of satellite data are needed. The aim of this study is to develop an innovative robust and accurate inverse model for the chlorophyll retrieval of Caspian Sea from MERIS (MEdium Resolution Imaging Spectrometer) data. We developed a new hybrid inverse model using the integration of ALM (Active Learning Method) and ANN (Artificial Neural Network) inverse models. The results of this study showed that it is very robust to noise and also demonstrated that it is very useful model for chlorophyll retrieval of remotely sensed data in the coastal (high chlorophyll concentration) and open sea (low chlorophyll concentration) waters. The main outcome of this research is an automatic code which is able to process satellite images automatically and enables robust water quality monitoring of different water bodies.
Field Experiences Using Foam to Cleanout Sour Gas Wells in Saudi Arabia
Authors: Al-Hakami Ibrahim , Franco Carlos , Leal Jairo Alonso , Garzon Francisco , Noguera Jose , Izquierdo Guillermo
Published: December 2007

The use of coiled tubing to perform fill clean outs or to remove scale build-up or any other type of restriction inside the wells is becoming one of the most common field applications in Saudi Arabia. In fact, based on the increasing scale tendency in the gas wells, Coiled Tubing scale cleanout represent one of the biggest challenges for Coiled Tubing service activities, especially in gas wells. The trend towards more complex well trajectories, lower bottom hole pressures because of reservoir pressure decline, heavier and harder scale materials and high H2S contents, impose operational constraints on this essential service; making the selection of the cleanout fluid an important component of the design criteria.

Inefficient wellbore cleaning is the main source of costly problems such as stuck CT pipe. A well-known solution to solve the problem is to increase the velocity of the cleanout fluid in the annulus, which will decrease debris concentration in the annular space. The increment of the annular fluid velocity is limited because of the CT friction and surface equipment. Under this scenario, the fluid with proper viscosity to transport the solids is required, even in low annulus velocity scenarios.

Foam was selected as the cleanout fluid for this particular type of wells because of its ability to keep the debris in suspension and transport it out of the well and to control the reservoir pressure to perform the cleanout operation in near balance or slightly overbalanced conditions.

This paper describes some field experiences using foam as a fluid to transport the removed material out of gas wells, independently of well deviation, using coiled tubing. It describes the technical details behind this approach as well as the operational results and best practices for field applications.
Technological Applications Redefining Mature Field Economic Limits
Authors: Abduldayem Mohammed A , Al Douhan Nader D. , Baluch Zulfiqar A.
Published: December 2007

Nowadays, high water-oil ratio producing fields are responsible for a significant portion of world oil production, particularly from mature fields where production practices are the key to managing operating costs and optimizing profit. In today's environment with relatively high oil prices, technology application in field management plays a critical role in improving production performance and recovery, as well as redefining the economic limit of the field.

Excessive water production is one of the main threats to the longevity of oil wells. It results in increased production cost and higher field capital investment requirements in surface facilities to produce and handle water. Saudi Aramco has taken major steps in applying technologies on both newly developed and mature fields. These technologies had contributed to a remarkable water production reduction in the Abqaiq Field. Technologies such as; smart completion, side tacking at the top of the reservoir, maximum reservoir contact (MRC) wells, Equalizer and interval control valve (ICV) production technologies, intermittent production strategy and rigorous water shut-offs for high water-oil-ratio (WOR) wells, has resulted in reversing the Abqaiq field's water cut trend from 42% in 2004 to 32% by the end of 2006.
Optimization of Gas Well Productivity by Controlling Water Production
Authors: Shar Amjad Hussain
Published: December 2007

It is seen that gas wells if produced without planned rates may produce waterpre-maturely. Production of water basically loads the subject well bygenerating hydrostatic head within the well tubing. Secondly the waterproduction alters the in-situ gas saturation in near well bore region resultingchange in the relative permeability. Both these reasons make the subject wellproblematic due to decrease in well productivity and increase in the welloperating cost. Also the handling of produced water is uneconomical in manycases.

The work done for this study is general in nature, though the essence ofthis work comes from data collected from different gas wells having waterproduction problem. This study gives an overview of all the methods andtechniques, which can be used for, expel-out such problems and optimize gasproduction. Main stress has been given on Tubing Performance Curve study inorder to select best tubing size and calculation of the optimum rates againstselected tubing size. General tubing performance curve are also presentedshowing the behavior of the well before and after water production.

On the basis of study of different techniques related to the Gas wellproduction optimization and water production control we became, able to give asolution of interchanging the well tubing strings without purchasing any newstring pertaining to large gas fields where different tubing sizes are used indifferent wells.

Introduction

It is considered that wells producing dry gas have usually lower flowingbottom-hole pressure [1]. Liquid loading happens when the gas does not haveenough energy to carry the water out of the wellbore. Water accumulates at thebottom of the well, generating backpressure in the wellbore and blocking gasinflow [2]. For the optimization of the production of the gas it is necessaryto unload that water from the wellbore so that there should occur a decrease inthe backpressure of the static water column.
Case History: Seismic Facies Analysis Based on 3D Multiattribute Volume Classification in Shadegan Oilfield – Asmari Reservoir, Iran
Authors: Arianfar Abdonabi , Khedri Behruz , Haghighi Maziar , Golalzadeh Alireza , Poladzadeh Mahmod , Mehdipour Zargham
Published: December 2007

Shadegan oilfield is located in Khuzestan province in southwest of Dezful embayment, southwest of Iran. The latest 3D surface seismic was carried out in 1999 over an area of 192 km2 in this field to resolve structural ambiguities, delineate exact dimensions of the field, estimate reservoir parameters and perform a seismic facies analysis over the field for producer zones of Asmari reservoir.

Asmari reservoir in this filed consists of three producer zones including zones 2, 5 and 6. This paper will discuss about facies analysis of these zones based on 3D seismic multiattribute volume classification.

A sophisticated approach was undertaken to perform multiattribute seismic facies analysis in the Asmari reservoir for each zone. Many lithology sensitive attributes were extracted from the post-stacked 3D seismic data and some of them were rejected using a multidimensional correlation technique in order not to take part in classification algorithm and determining the optimum set of attributes to use in the classification. This helped with data redundancy problems inherent in multiattribute analysis and avoiding independent attributes by choosing an appropriate set of attributes for the classification. So, the seismic attributes used for the facies classification included Signal Envelope, Heterogeneity Seismic Amplitude, Integration Seismic Amplitude, Magnitude Seismic Amplitude and Volume Reflection Spectrum. The objective was to integrate the seismic attribute information through the use of an unsupervised clustering technique. Clustering techniques are widely recommended tools for classification issues.

The k-means algorithm is widely accepted as the standard technique of detecting different classes automatically from the measured data. This algorithm provided a facies database that was used to estimate lithofacies over the whole field. Using the clustering technique, three major lithologies including sandstone, carbonate and shale have been classified and displayed for each producer zone. Classified facies were calibrated to drilled wells and the results were confirmed.