bluuebunny/crossref_metadata_2025 huggingface dataset:
Successful Drilling and Deployment of an Open Hole Multistage Fracturing System in a Deep and Hostile Sandstone Gas Reservoir
Authors: Ab. Hamid Abdul Halim , Khalil Mohammed E. , Al-Mohammad A. K. , Al-Khamees Shaker A. , El-Mofty Wael , Johnston Bryan , Wilson Stuart
Published: May 2011

The pre-Khuff Unayzah gas reservoir in Saudi Arabia is a competent sandstone formation with Unayzah-A and B/C sand units separated by a variable thickness siltstone unit, which is regarded as a sealing barrier between the Unayzah-A and Unayzah-B reservoirs. They are known to contain significant reserves of natural gas, however they are at low permeability, which has made it difficult to optimize production. Drilling through highly abrasive sandstone at high bottom-hole temperatures (BHT) has also been challenging. To meet Saudi Arabia's future gas requirements, it was essential to establish a means to exploit these reserves.

Multiple methods have been used to drill and complete these wells, including long horizontals and multilaterals. Well trajectories were planned with the horizontal sections drilled along the direction of maximum in-situ stress (parallel to the fracture plane) for enhanced wellbore stability and fast penetration rates. Fracture treatments were pumped generating mostly longitudinal fractures propagating in the same direction as the maximum horizontal stress (parallel to the wellbore axis) resulting in a poor fracture network and suboptimal production results.

In April 2010, a horizontal well was successfully drilled into the Unayzah reservoir towards the minimum in-situ stress direction and completed with an open hole, multistage (OHMS) fracturing system. A four-stage proppant fracturing job was successfully conducted in November 2010 without issues. Unique fracture signatures were observed in each zone and production from the well has exceeded expectations.

This paper analyzes Saudi Aramco's successful initiative to drill the lateral section along the direction of minimum in-situ stress and the challenges associated with wellbore stability, a highly abrasive formation and high static BHT. Also highlighted are Saudi Aramco's successful techniques for deploying the OHMS fracturing system with special emphases on borehole preparation. Lessons from the successful drilling/completion of this well could have a significant impact on how future Unayzah wells are drilled and completed to maximize productivity from tight gas reservoirs in Saudi Arabia.
Advanced Cementing Systems for Deep Sour Gas Wells
Authors: Liu Z. , Sun J. , Nasr-El-Din H. A. , Shan H. , Xiao Z.
Published: May 2011

Cementing deep sour gas wells presents a number of challenges to well construction engineers. High bottom hole static temperature (BHST from 250 to 400°F) and pressure (mud density > 2.0 g/cm3), excessively long job times due to the constraints imposed by tight annular clearances (casing OD/hole size > 0.85), long cement columns (interval length > 450 ft), and harsh conditions (H2S, CO2, salt layer, high leakoff). All of these factors contribute to the operational risks not only during placement of the cement slurry in the wellbore, but also during the life of the well. Field data indicates that current cement systems were not able to address these challenges, and as a result, the outcome obtained from various cementing jobs was below expectation.

Advanced cement systems were developed to address the problems encountered in cementing deep sour gas wells. These systems were applied in the field with great success. Multi-functional fluid migration control systems together with engineering particle sizing technique significantly improved the performance of cementing jobs, including: superior fluid migration control, predictable thickening time, stable API properties at high slurry densities, and great resistance to H2S, CO2 and salt corrosion. A unique retarder used in the lead slurry helped in developing compressive strength rapidly on the top of cement column. An effective laminar flow displacement technique was also used to displace drilling fluids effectively to enhance its placement and improve the cementing bond.

This paper details a thorough and systematic laboratory development of innovative cement systems and presents case histories to document their effectiveness for cementing deep sour gas wells.
Success Criteria for Multistage Fracturing of Tight Gas in Saudi Arabia
Authors: Rahim Zillur , Al-Kanaan Adnan , Johnston Bryan , Wilson Stuart , Al-Anazi Hamoud , Kalinin Daniel
Published: May 2011

The purpose of open-hole multi-stage (OHMS) fracturing is to improve hydrocarbon production and recovery in moderate to tight reservoirs. To date, 17 OHMS fracturing systems have been installed in deep gas carbonate and sandstone wells in Saudi Arabia. Of these, 14 installations have been stimulated (acid or proppant fractured) and flowed back.1 Overall, the production results from the use of OHMS systems deployed in the southern area gas fields have been very positive with some variation – most of the wells responded positively and are excellent producers (>20 million standard cubic feet per day (MMscfd)), some showed average results, 8-12 MMscfd, and a few, completed in tight reservoir, produced at relatively low rates, <3 MMscfd, and did not carry enough wellhead pressure to be connected to the production grid. This paper will explore the factors that impact successful OHMS completion systems. Some important factors include types of OHMS used, formation properties, completion liner size, packer types, number and size of stimulation stages, treatment types, well azimuth, and fluids pumped. Conclusions are drawn based on careful data analysis to confirm the best practice for successful OHMS deployment and conducting effective fracture treatment.

This paper uses extensive field data and correlates factors to show the applicability of OHMS technology. Analysis will cover pre- and post-stimulation data showing the results from the treatments. This analysis will show the factors that contribute to successful deployment of the completion system, higher production rate, and the choice of the right candidates to obtain positive results from the treatment. This paper will show that while the various well and reservoir characteristics have a significant influence on overall well productivity, the completion type is critical and plays a central role on the success of the stimulation treatment and final production levels.

OHMS systems have been deployed extensively in North America, but they are relatively new in the Middle East. This is because the conventional horizontal wells are usually high producers and only require small stimulation treatment to clean up the near wellbore area from drill-in induced damage. With the exploration of tight gas and unconventional resources, the need to conduct multi-stage fracturing (MSF) is increasing. The tight gas zones in Saudi Arabia are typically deeper and more complex with higher temperatures and pressures than most tight gas zones in North America and therefore require much more accuracy and precision in OHMS technology applications. This paper discusses the factors that contribute to the higher production levels for these types of completion systems.
Effects of Carbon Dioxide Injection in Reactive Carbonates: Computational Rock Physics Basis for Time-Lapse Monitoring
Authors: Nur Amos , Vanorio Tiziana , Diaz Elizabeth
Published: May 2011

Carbon dioxide injection into natural reservoirs has been used for enhanced oil recovery as well as, more recently, for geologic sequestration. In both technological applications, of major interest is remote sensing of the progress of the injected carbon dioxide through the subsurface as well as its effects on the physical characteristics of the rock, including the elastic, storage, and transport properties. Whereas it may be safe to assume that the presence of carbon dioxide does not alter the mineral matrix in most clastic reservoirs, the situation is very different in carbonates where such alteration may occur in real time, in a matter of hours, days and, certainly, months.

Physical laboratory experiments have confirmed that the carbon dioxide interacts with formation water and, eventually, with the mineral matrix (Vanorio, T. et all, 2008). These chemical processes alter the pore space geometry in carbonates and can even create such flow conduits as relatively large wormholes. This pore-space and matrix alterations can definitely affect the elastic properties of carbonate rock, which are crucial in interpreting the 4D time-lapse seismic data for pore-fluid content in space and time. Because of the changes occurring in the mineral matrix during carbon dioxide injection, traditional fluid-substitution techniques often do not work in such reactive rock and, hence, can be misleading during seismic data interpretation.
Fluid Flow Characterization of Chemical EOR Flooding: A Computerized Tomography (CT) Scan Study
Authors: Bataweel M. A. , Nasr-El-Din H. A. , Schechter D. S.
Published: May 2011

Chemical flooding methods are used to recover residual oil left after water flooding. Several recovery mechanisms were suggested to improve the displacement effectiveness of the trapped oil. Reducing IFT, mobility control and wettability alteration are the main recovery mechanisms during chemical flooding. Understanding which recovery mechanism that dominate during recovery process helps selecting and optimizing which chemical process to be used.

An experimental study of 4 chemical flood experiments were visualized with computed tomography (CT) in sandstone cores at room temperature. The experiments were conducted to study four different chemical flooding processes: polymer, surfactant, surfactant-polymer (SP), and alkali-surfactant-polymer (ASP). Oil recovery, and oil distribution in the core were evaluated after the chemical flood.

The experimental results obtained from the core flooding experiment shows best recovery was during ASP and SP flooding with some residual reduction in permeability caused by using polymers. The lowest recovery was obtained during surfactant flooding, which prove that IFT reduction can’t improve recovery without the aid of mobility control by polymers.
Understanding Heavy Oil Fluid Sensitivity for Seismic Reservoir Characterization in Middle East Carbonates
Authors: Bakhorji Aiman M. , Otaibi Mohammad G. , Ahmed Mohammad Mukarram
Published: May 2011

Heavy oil is defined as viscous fluid having an API gravity of less than 22°. Seismic velocities are sensitive to heavy oil properties and especially to reservoir properties, such as temperature and pressure. Laboratory studies have shown that heavy oils with much lower API values can act as a semi-solid, and therefore support shear wave propagation. In such cases, using a conventional Gassmann fluid substitution model (Gassmann, 1951) to understand the fluid scenarios is not applicable for seismic reservoir characterization.

From the different published approaches for modeling fluid behavior in heavy oil reservoirs, the extended Gassmann (Ciz and Shapiro, 2007) is normally used as a lower bound (for low frequency and moderate fluid shear modulus change) for fluid substitution sensitivity and the Coherent Potential Approximation (Berryman, 1999) is used as an approximate upper bound (for high frequency). The true fluid substitution sensitivity for heavy oil is somewhere between these two bounds. A recently developed non-Gassmann rock physics workflow, in principle, provides a consistent approach to estimate (from calibration data, e.g., log data, core measurements) and model the data within these two elastic bounds.

A pilot study was undertaken to understand heavy oil's elastic properties in a Mesozoic carbonate reservoir located in Saudi Arabia. Due to the lack of core-fluid measurements, a range of heavy oil fluid parameters, such as gas-oil ratio (GOR), temperature, pressure and API range were tested to understand their effects on the elastic properties.
Stability of Local-equilibrium Foam States in EOR Processes
Authors: Ashoori E. , Marchesin D. , Rossen W. R.
Published: May 2011

The use of foam for mobility control is a promising mean to improve sweep efficiency in EOR. Experimental studies discovered that foam exhibits three different states (weak foam, intermediate foam, and strong foam). The intermediate foam state is found to be unstable in the lab whereas the weak- and strong-foam states are stable.

The model of Kam (Colloids Surfaces A, 2008) is the only mechanistic foam model that can fit a variety of steady-state experimental data including multiple steady states. This model is modified from a previous mechanistic foam model to resolve the intrinsic instability of the strong-foam state. Simple finite-difference simulations have found that an arbitrary perturbation grows for the unstable intermediate foam but diminishes for the strong- and weak-foam states.

The issue of the stability of foam states, especially the strong-foam state, is a serious concern in application of foam in EOR. Instabilities may rule out one or more states and consequently have considerable effect on reservoir sweep efficiency and injection pressure.

Here, for the first time the stability of the various foam states is investigated by a semi-analytical stability-analysis method. We demonstrate the instability of most intermediate states, consistent with the laboratory observations. However, fine analysis reveals a slight instability of the strong-foam state. We show that the diffusion, whether introduced artificially by the finite-difference scheme or representing physical dispersion, damps this slight instability. We obtain good agreement with finite-element simulations with and without diffusion.
Quantitative Corrosion Assessment with an EM Casing Inspection Tool
Authors: Brill Thilo Michael , Le Calvez Jean-Luc , Demichel Cindy , Nichols Edward , Bermudez Fernando Zapata
Published: May 2011

A recently introduced electromagnetic (EM) casing-corrosion evaluation tool provides total metal thickness, tubular internal diameter, and defect imaging inside single and multiple casings. Quantitative assessment of ongoing corrosion enables timely mitigation strategies to prevent leaks, environmental damage, or catastrophic failures. This slim tool allows measurements through production tubing, eliminating the risk and saving the cost of tubing removal. It provides a high-resolution casing assessment.

EM assessment uses magnetic fields from induced eddy currents to determine the casing thickness and the inner casing diameter. Receiver coils mounted along the tool axis receive these EM fields to give average metal loss; small pad sensors on 18 arms around the tool perimeter provide an image of local metal loss. The measurement resolution is determined by propagating laboratory-measured noise to uncertainty in the computed casing thickness. These calculations are verified with numerical simulation and field validation.

Advanced signal processing converts the raw data to high-quality logs. Deghosting removes the double responses seen as a defect first passes by the receiver coils and later by the transmitter.

Several field examples show the quantitative, high-resolution assessment of pipe condition. Log examples show detection of casing joints, multiple casings strings, and the presence of corrosion damage in the low- and high-frequency images.
Rheological Transition during Foam Flow in Porous Media
Authors: Simjoo M. , Nguyen Q. P. , Zitha P. L.
Published: May 2011

The flow of nitrogen foam in Bentheimer sandstone cores previously saturated with a surfactant solution has been investigated experimentally. The displacement process was visualized with the aid of a CT scanner. The CT data were analyzed to obtain water saturation profiles at different times. The pressure drops measured over core segments were recorded to determine the foam mobility. It was found that foam undergoes a transition from a weak to a strong state at critical gas saturation of Sgc = 0.75±0.02. This effect could be interpreted successfully in terms of the surge of the yield stress of the foam at this value. It is suggested that a confined jamming is most likely responsible for the mobility transition.
Effect of Temperature, Oil Asphaltene Content, and Water Salinity on Wettability Alteration
Authors: Al-Aulaqi Talal , Grattoni Carlos , Fisher Quentin , Musina Zenfira , Al-Hinai Suleiman
Published: May 2011

It is well known that thermal enhanced oil recovery (EOR) improves recovery by lowering the oil viscosity and so is usually performed in heavy oil reservoirs. Wettability alteration may also occur during thermal EOR in which case it may also affect production rates in light oil reservoirs.

The interaction between crude oil-brine on different rock surfaces as a function of temperature is not well defined. For example, for silicate surfaces some authors reported a complete reversal of wettability, from a predominantly water-wet system at lower temperature to a predominantly oil-wet system at higher temperature, while others found that the degree of water wetness increased with temperature.

In this study, the microscopic behavior, by direct observation, of oil and brine on silicate surfaces at different temperatures up to 60°C was studied. Wetting preference of silica as a function of brine salinity, oil type and temperature has been studied during long time interaction (aging) tests. Four light crude oils of different asphaltene contents and brines of different composition have been used in this work.

The study shows that as the temperature increases, the silicate wettability becomes more oil-wet as the asphaltene content of the crude oil decreases. When asphaltene is removed from a crude oil, the degree of oil-wetness is reduced. Regarding the brine effect, in acidic-lower salinity (NaCl brine) where oil adhesion occurs readily, hysteresis between advancing- receding contact angles is larger than for a neutral pH with high salinity brine. The consequence of these observations in flat surfaces is validated by flowing oil and water through glass micromodels, which provide wettability alteration evidence for lower salinity brine and as temperatures increases.
Inaccessible Drilling Targets and Casing Exits Made Possible by the Alleviation of Excessive Torque and Drag
Authors: McCormick John , Hogg Cliff
Published: May 2011

Extended reach and highly deviated wellbores are becoming more and more commonplace in the oil and gas industry, bringing with them a host of challenges related to many aspects of the well construction process. Multilateral wells are an excellent example of this situation due to the doglegs formed when milling and drilling side tracks, the deviation of the hole, and the necessity of getting equipment to bottom and setting weight down to set and operate that equipment, especially during casing exits. Advanced technology has been developed to drill multilateral wells, but even this equipment can run up against its limitations in extremely challenging wells as operators continue to push the technology envelope. It is in these scenarios that combining technologies can provide the solution to safely and successfully manage downhole operations like casing exits and the drilling and completion of multilateral and extended reach wells.

Such technology combinations can have a significant effect, not only on the ability to achieve far reaching targets, but also on the well construction time required and therefore the overall operational costs. In this paper the authors will focus on the combination of technologies to create multilateral wells in Extended Reach Well (ERW) scenarios where excessive torque and drag effects can adversely impact: Torque and weight while milling – associated with sidetracks through cased hole.Getting tools to target depth.Getting the loads at depth that are required to activate, set or release equipment downhole.

They will review a hollow whipstock multilateral system and sub-based torque and drag reduction tools and present case studies of wells drilled successfully with these technologies, including the creation of the worlds’ deepest known horizontal casing exit.
Modeling and Simulation of Structural Deformation of Isothermal Subsurface Flow and Carbon Dioxide Injection
Authors: El-Amin M. F. , Negara A. , Salama A. , Sun S.
Published: May 2011

Injection of CO2 in hydrocarbon reservoir has double benefit. On the one hand, it is a profitable method due to issues related to global warming, and on the other hand it is an effective mechanism to enhance hydrocarbon recovery. Such injection associates complex processes involving, e.g., solute transport of dissolved materials, in addition to local changes in density of the phases. Also, increasing carbon dioxide injection may cause a structural deformation of the medium, so it is important to include such effect into the model. The structural deformation modelling in carbon sequestration is important to evaluate the medium stability to avoid CO2 leakage to the atmosphere. On the other hand, geologic formation of the medium is usually heterogeneous and consists of several layers of different permeability. In this work we conduct numerical simulation of two-phase flow in a heterogeneous porous medium domain with dissolved solute transport as well as structural deformation effects. The solute transport of the dissolved component is described by concentration equation. The structural deformation for geomechanics is derived from a general local differential balance equation with neglecting the local mass balance of solid phase and the inertial force term. The flux continuity condition is used at interfaces between different permeability layers of the heterogeneous medium. We analyze the vertical migration of a CO2 plume injected into a 2D layered reservoir. Analysis of distribution of flow field components such as saturation, pressures, velocities, and CO2 concentration are presented.
Elastic Properties of Emulsified Acids: Effect of Emulsifier Concentration and Temperature
Authors: Sayed M. A. , Nasr-El-Din H. A.
Published: May 2011

For many years, hydrochloric acid was the main fluid used in carbonate reservoirs well stimulation. Hydrochloric acid has many advantages including high dissolving power and water soluble products, but it also has some disadvantages such as high reaction rate and high corrosivity. There are other acid systems that can be used to minimize these effects; one of the most important systems is the emulsified acid. The emulsified acid offers the advantage of minimum additives and minimum corrosion possibilities. Researchers correlated the droplet size of the dispersed phase (acid) and emulsifier concentration to the viscosity, stability, and reaction kinetics of emulsified acids.

The effect of emulsifier concentration, acid volume fraction and temperature on elastic properties of emulsified acid was not studied before. The main objective of this work is to study the effect of these parameters on the elastic properties of the emulsified acid. In order to perform that, a HPHT oscillatory rheometer was used.

The general behavior of emulsified acid is that the viscous modulus (G″) is always higher than the elastic modulus (G′). As the emulsifier concentration increases, viscosity increases and the viscous behavior dominates for these fluids. As the acid volume fraction increases, the viscous modulus (G″) increases. At low emulsifier concentration (2 vol%), the elastic modulus (G′) and viscous modulus (G″) increase with increasing the temperature up to 170 °F and then decrease. At higher emulsifier concentration, the elastic modulus (G′) almost does not change with temperature and the viscous modulus (G″) always decreases with increasing temperature. These results will help production engineer to better design acid treatments that depend on emulsified acids.
Valhall – Pushing the Limits for Openhole Zonal Isolation — Qualification and Field Trial of 10,000-psi Oil-Swelling Packers
Authors: Koløy Tom Rune , Andersen Kristian , Nijhof Jeroen
Published: May 2011

BP-Norge AS operates the Valhall Field in Norway and relies on multi-zone water injection for reservoir management and control of unwanted water production for Valhall wells. A produced water shutoff method in this field is necessary, and equipment must be capable of maintaining integrity at differential pressures of 10,000 psi during prop-fracture stimulation of the individual zones in the oil-producing wells. The operator wanted to find a new completions solution that would enable long horizontal reservoir sections to be completed and stimulated with the capability to shut-off unwanted water at a later time during well life.

Swellable elastomer packers (SEPs) were suggested to the operator as a possible method for zonal isolation. Unfortunately, three attempts to qualify the currently available SEPs to the 10,000-psi differential pressure (DP) for Valhall were all unsuccessful; therefore, the decision was made to try a new design that used an innovative mechanical end-ring system. This configuration uses a solids-laden oil-based mud (OBM) to expand the element installed on the outer surface of the basepipe that forms part of the reservoir liner. This eliminated the need to spot dedicated swelling fluid.

The changed configuration represented a significant step change in the design methodology of SEPs. The new design not only enabled the reduction of element length and packer OD, but it also could withstand the high DP ratings as well as increased the DP ratings of long SEPs. The new configuration required qualification testing, and this paper presents the case history of the operator's full-scale qualification testing up to 10,000 psi across two 5-meter packers as well as the improvements the new SEPs could offer over previously used equipment and methods.

The paper will also discuss the design, other potential applications, and the advantages of the new SEP design. A case history of the first installations of the new SEP worldwide will be presented as well.
Effects of Rapid Gas Decompression on Swellable Rubber and Common Oilfield Rubber Compounds.
Authors: Young Dustin , Sevre Alf K. , Smith Peter E. , al-Madlouh Mohammed , Awang M. Zaki
Published: May 2011

Rubber or elastomeric seals are flexible polymers used in a variety of applications in many industries and have become more widely used in oilfield equipment as polymer technology has advanced. The seals are used in many oilfield applications and can be damaged during a rapid decrease of pressure after being exposed to environments containing gas. This phenomenon is known as explosive decompression (ED) or rapid gas decompression (RGD).

RGD damage can be manifested as splits, cracks, or bubbles in the seals, depending on the rubber type, length of exposure to the gas, and the rate of pressure decrease. Damage caused to a seal by RGD can range in severity from a slight weakening of the physical properties of the rubber to a catastrophic failure of the integrity of the seal. Both surface operations and downhole conditions are capable of causing RGD, which, can result in failure of the equipment using the seals.

This paper discusses tests performed on various elastomeric samples, including swellable rubber, to determine the effects that RGD will have on the seals under varying conditions. The tests exposed each sample to a range of pressure drops and gas exposure times. The samples were analyzed after each test for physical changes and signs of RGD damage. The purpose of mapping the effects of RGD on multiple samples and the various conditions to which the seals were subjected was to develop a better understanding of the conditions leading to RGD damage and to identify operations at risk for causing RGD damage to elastomeric seals. The testing and results are further discussed in this paper.
Coreflood Study of Low Salinity Water Injection in Sandstone Reservoirs
Authors: Nasralla Ramez A. , Nasr-El-Din Hisham A.
Published: May 2011

Water chemistry has a significant effect on oil recovery. It was found that low salinity water has a good potential for improving oil recovery in sandstone reservoirs. However, the mechanisms by which low salinity water injection works are still uncertain. This means the optimum conditions for improving oil recovery are unknown. In this paper, coreflood experiments were conducted to understand how cation type in injected water may affect oil recovery. In addition, testing multiple salinities helped to identify the optimum salinity.

Several waterflood experiments at high pressure-high temperature (HPHT) were conducted on Berea sandstone cores, 6 in. length. Single cation water solutions were prepared to be injected in cores at different concentrations of NaCl, CaCl2, and MgCl2. Effect of oil composition and characteristics on improvement of oil recovery by waterflooding was investigated by using two different types of crude oils. In addition, core effluent fluid was collected and analyzed using ICP-OES and Spectrophotometer to study interactions between rock and injected fluid.

This work contributes to the understandings of impact of cation exchange on oil recovery by low salinity water flooding. Experiments showed that exchanging certain cations is the primary reason of higher oil recovery. Absence of Ca2+ in injected water allowed water to leach Ca2+ from the rock surface which, caused surface instability and allowed higher oil volume to be released from the rock surface and be recovered. Results demonstrate that the existing cations in the injected water solution have more dominant effect on oil recovery than the concentration of salts in water. In addition, oil composition has a significant effect on the efficiency of waterflooding, and hence oil recovery. These findings help in introducing the optimum water salinity.
First Successful Multilateral Well Logging in Saudi Aramco: Innovative Approach toward Logging an Open Hole Multilateral Oil Producer
Authors: Al-Momin Ali , Zeybek Murat , Azrak Abdul Wahab , Burov Anton
Published: May 2011

Drilling of multilateral wells has increased significantly over the past few years as one of the reservoir development strategies to maximize well productivity through maximizing reservoir contact (MRC). These complex wells impose big challenges with respect to well accessibility for rigless well intervention. Means to access those wells were developed to perform conventional coiled tubing (CT) operations, such as reservoir stimulation.

One of the existing challenges is to perform production logging in these complex wells to quantify oil and water contribution of each open hole lateral and pinpoint fluids entry, mainly deep water inside these laterals.

This challenge was encountered in a multilateral oil evaluation producer, which was drilled in a carbonate oil reservoir but died shortly after being put on production due to high water production from an unknown source. This necessitates the logging of each of the well's laterals to identify the water contribution intervals to allow for the proper remedial action on this well, as well as to determine the optimal well completion for this type of reservoir, including inputting to geological modeling.

At present, there is no single production logging tool (PLT) that can be utilized to log each lateral selectively. Therefore, a combination of a multilateral tool along with a reservoir saturation tool was utilized to locate and access laterals selectively and to record a pulsed neutron log to determine the produced water velocity across each of the laterals. The pulsed neutron log was combined with three phase hold-up logs allowing the generation of production profiles of each lateral as well as the detection of water entries across these laterals.

This paper discusses the planning, execution and results evaluation of the logging job on an openhole multilateral oil producer along with all the techniques, which were employed to overcome challenges encountered along the way to acquire the best possible data on each lateral.
Multi-Physics Approach for Aging Assessment of Carbonate Rocks
Authors: Pairoys F. , Al-Zoukani A. , Nicot B. , Valori A. , Ali F. , Zhang T. , Ligneul P. , Akbar M.
Published: May 2011

Wettability influences the flow motion of hydrocarbons in carbonate oil reservoirs: it is measured in laboratory with specific procedures including assessment of its initial value. Conventional or special core analysis requires good cleaning of the cores. Additional measurements like relative permeability or capillary pressure for instance require restoration of the initial wettability conditions of cores by aging them. The routine methods for assessment of wettability are USBM and Amott-Harvey (A-H) tests, which involve large amount of efforts and time. In this study we replace these tedious processes by tracking the aging through repeated NMR and resistivity measurements.

Four core plugs, two dolomites and two limestones, were selected from twenty carbonate plugs collected from different outcrops. After saturating the samples with brine, the cementation factor m was calculated. NMR T2 relaxation was performed as a reference on fully brine saturated samples. Crude oil was injected into the plugs until they attained Swi. An NMR T2 was measured on them before aging. Then one limestone and one dolomite were immersed in crude oil and placed in an oven at reservoir temperature, while the two other samples were loaded in resistivity core holders under same reservoir temperature and confining pressure to age them. Resistivity was measured continuously while NMR T2 were recorded at different time intervals to observe the response of the aging core samples to independent physical investigations.

The NMR and resistivity measurements were used to identify the wettability alteration. The resistivity change showed a continuous wettability change in the plugs, which was also confirmed by the continuous change in the NMR T2 response. Both methods showed that dolomite was more prone to becoming oil-wet than limestone. It was verified by USBM and Amott-Harvey tests on same plugs. Further tests will be necessary to validate the generality of the overall workflow.
A Simple Analytical Formula to Estimate Fracture Connectivity
Authors: Ozkaya Sait. I.
Published: May 2011

A simple expression is derived for average fracture intersections per fracture, λ as the product of fracture density, average length and angular standard deviation for 2D and 3D cases. The calculated λ value quite accurately estimates the observed actual λ values for a variety of cases including one or two fracture sets, truncated or not-truncated fractures, and log normal or power length distribution. The validation is confined however only to 2D stochastic fracture models. The 3D equivalent formulae were not validated. The formula fails to estimate number of fracture intersections accurately when fractures are clustered. Fracture clusters could either be fault related fracture corridors or highly fractured layers. In either case, it is necessary to calculate λ for each fracture corridor or each fractured layer with different fracture density.

The relationship between λ and fracture connectivity and percolation were investigated using several stochastic fracture models. λ seems to be a reasonably good estimator of fracture connectivity, which we define as percent of fractures within the largest fracture cluster. The relationship between number of fracture intersections and percolation threshold is, however, weak because percolation threshold is dependent on the relative length of fractures with respect to the distance between two opposite ends of a fractured medium.

We tested the value of λ from borehole image data as a measure of fracture connectivity by comparing it with open hole log and production flow profile in an actual well. λ was calculated for highly fractured low porosity layers and found to be far below the values expected for fracture connectivity. Production log flow profile and open hole logs confirmed the result. There is no flow from the fractured low porosity layers, but all the flow is from a high matrix porosity / permeability layer with sparse or no fracturing. Open hole logs also show injection water encroachment only within the permeable matrix layer.
Study and Field Application of Inorganic Composite Blocking Agent with Ultra-low Density for Water Coning Control in High Temperature and High Salinity Fractured-vuggy Carbonate Reservoir
Authors: Caili Dai , Qing You , Long He , Qin Guowei , Ping Wang , Feng Decheng , Fulin Zhao
Published: May 2011

Tahe oilfield in China belongs to fractured-vuggy carbonate reservoir with high temperature (100~130 celsius degree) and high salinity (two hundred thousand mg/L containing ten thousands mg/L of Ca2+ and Mg2+). After exploration for many years, the bottom water cones through fractures and vugs into production wells and then oil production declines obviously. In order to solve this problem above, a new inorganic composite blocking agent is proposed and developed in this paper. This new blocking agent is composed of superfine cement, strengthening agent, density adjusting agent, bridging agent, suspension dispersing agent, retardant and drag reducer. By adjusting the different proportions of components to make sure the density of this new blocking agent is in 1.00~1.10g/cm3 between oil (0.80~0.98g/cm3) and water (1.14g/cm3) which can build up packer existing in water-oil transition zone to control bottom water coning caused by gravity segregation resulting from density difference. Then the agent could expand sweep volume of bottom water and enhance oil recovery. This new blocking agent had been applied in one production well in Mar 2009, by Jul 2010, the accumulated oil increment is 1753.31t, the water cut decreased from 99.23% to 91.64% and the input-output ratio is up to 1:2.0. The success of field test confirmed that this new blocking agent is quite suitable for controlling bottom water coning and has a broad application prospect.
An Experimental Study of Compositional Displacements in Multi-Layered Porous Media
Authors: AlAli A. M. , AlHamdan M. R. , Cinar Y.
Published: May 2011

In this paper, we present a laboratory study that investigates the behaviour of compositional displacements in multi-layered porous media. A quasi two-dimensional glass bead pack was used in the experiments. The porous medium had three uniform layers with each having a different permeability because of the different glass beads. An analog two-phase three-component liquid ternary system was used in the experiments at ambient conditions to mimic a condensing gas drainage displacement under reservoir conditions. We report a total of nine experiments which include three horizontal and six vertical cross-section displacements with different injection and initial fluids. The fluids chosen represent immiscible, near miscible and first-contact miscible systems. The effluents were collected for each experiment and their compositions were measured using gas chromatography. Several snapshots of the fluid distributions in the porous medium were taken during each experiment. The experimental results show that the horizontal displacements gave a better sweep efficiency. Most of the displacements took place in the high-permeability layer with the low-permeability layer not even touched, gravity effects were favourable in the vertical cross-section displacements where the high-permeability layer was at the bottom, and the gravity reduced the swept area in the flood with the flipped vertical cross-section model. The measured compositional data indicates differences in the compositional paths for different displacements.
Effective Well Placement and Trajectory Planning Approach through Collaboration Environment Tools
Authors: Al-Baqawi Ahmed M. , Al-Naim Hamad A. , Araque Telemac Arcides J. , Habbtar Ali H. , Ismail Menhal A. , Al-Kanan Adnan A. , Al-Utaibi Abdullah A.
Published: May 2011

Well placement and trajectory planning is a critical and challenging task in any Oil & gas field development plan. This has always been a task that requires a strong team effort to ensure the best predictions and estimations are performed to penetrate the desired reservoir development zones and achieve the expected production rates. Numerous iterations with a high level of interaction between Reservoir Management, Reservoir Simulation, Reservoir characterization, Geology and Geophysics are expected when planning a new well or a difficult sidetrack.

Each member of the well planning team has his/her own environment along with dedicated standalone software tools. Today, with the introduction of the Intelligent Field center to provide the collaboration environment for the involved expertise along with the proper tool to offer a strong integration of different data sources in a single software environment that allows a team of field geologist, geophysicist, reservoir and simulation engineers to evaluate the best prospects available in planning any new drilling opportunity, furthermore the team is able to choose the best well azimuth and inclination based on reservoir properties and performance.

This paper discusses a newly integrated well planning process utilizing a collaboration environment to review seismic, well log cross sections, historical production and simulation predictions enabling the well planning team to place their gas wells using a reservoir 3D viewer, incorporating the reservoir simulation model, and run various cases and sensitivities. In This paper, full examples illustrate how effective software integration can optimize the time required to plan a new well without overlooking any important aspect. In addition, the paper discusses the lessons learned from this experience and how this approach changes the mechanism of an integrated well planning team working together.
Smart Combination of Technology Tools Resulted in Successful Rigless Stimulation on a Tri-Lateral Well, Case Study
Authors: Al-Zain Ahmed , Al-Gamber Abdulwafi , Said Rifat
Published: May 2011

Drilling horizontal wells has become the more commonplace in many Saudi Aramco fields. Recent advances in drilling and completion practices enable the drilling of more complex wells with various types and shapes such as extended reach wells, bi-laterals and multi-laterals for providing maximum reservoir contact. These complex wells impose great challenges with respect to rigless well interventions. One of the initial well interventions, which follow drilling completion, is acid stimulation to remove formation damage. The challenges raised because of well complexity include accessing the laterals, reaching the end of each lateral and properly distributing treatment fluids over entire horizontal sections.

Effective rigless interventions in these challenging wells have limitations and technologies are still evolving. Deployment of tools and fluids downhole is no more possible through conventional coiled tubing applications. New techniques have been developed to assist coiled tubing (CT) to access laterals and extend their reach. In addition, recent advancement of CT bottom-hole assembly (BHA) allows combining services of more than one function such as deploying tools and fluids and at the same time acquiring vital downhole data.

The fiber optic enabled CT (FOCT) provides combined services of data acquiring on real time and running crucial CT technology tools. By the virtue of the optical fiber, distributed measurements could be made available to obtain temperature profiles. The temperature surveys allow evaluating flow distribution through temperature responses; hence, optimizing acid stimulation. FOCT with a flow-through BHA coupled with smart combination of technology tools such as a multi-lateral tool (MLT) and a mechanical drag reducer tool provides integrated services.

This paper highlights the first ever worldwide combination of technology tools via FOCT for acquiring downhole data on real time and technology tools for accessing and extending the reach of the CT for stimulating a tri-lateral oil producer in a major carbonate reservoir in Saudi Arabia. This combination has resulted in successful acid stimulation of all three laterals. The paper also discusses in detail the application of distributed temperatures for placing treatment fluids and experience gained.
An Accurate Prediction of CO2 Minimum Miscibility Pressure (MMP) Using Alternating Conditional Expectation Algorithm (ACE)
Authors: Alomair Osamah , Malallah Adel , Elsharkawy Adel , Iqbal Maqsood
Published: May 2011

Miscible gas injection nowadays becomes an imperative enhanced oil recovery (EOR) approach for increasing oil recovery. Due to the massive cost associated with this approach a high degree of accuracy is required for predicting the outcome of the process. Such accuracy includes, the preliminary screening parameters for gas miscible displacement; the "minimum miscibility pressure" (MMP) and the availability of the gas. All conventional and stat-of-the-art MMP measurement methods are either time consuming or decidedly cost demanding. Therefore, in order to address the immediate industry demands a nonparametric approach (ACE) is employed in this study to estimate an important parameter MMP. ACE algorithm correlates optimal transforms of a set of predictors with an optimal response transform. Finally, the proposed model has produced a maximum linear effect between these transformed variables. More than 100 MMP data points are considered both from the relevant published literature and experimental work. The test data points also MMP measurements that are experimentally obtained for Kuwaiti crude Oil. The proposed model is validated using detailed statistical analysis and it reveals that the results are more reliable than the existing correlations for pure CO2 injection to enhance oil recovery. In addition to its accuracy, the ACE approach is more powerful, quick and can handle a huge data.
Exceeding Well Life Design in Mature Field Using Well Integrity Management System
Authors: Calosa Weka Janitra , Rahman Hibatur , Dewanto Christianto Widi
Published: May 2011

High oil prices, new technology to increase oil recovery and government incentives can allow economic oil production to exceed the well design life. However, well life extension may result in more frequent critical failures involving leakages to the environment and structural safety issues during well service jobs.

Well Integrity management is a way to keep oil flowing from mature fields with extended wells lives with an environment friendly safe operation. This paper discusses the well integrity system implementation in a field in the Malacca Straits PSC, which contains mature oil fields with more than 30 years of oil and gas production.

This field has well integrity problem including leaking wellheads, severe corrosion of well components, failure of cement bonding, and land subsidence.

The well integrity management system assesses each well, evaluates the well operation in term of safety, and provides timely recommendations on remedial actions to keep the well producing.

The system also carries out quantitative data analysis and provides feedback to the operator about the condition of individual wells and overviews of whole field integrity.

The benefit is longer economic production with safe operational practices. This system was implemented in the MSAC-14 well, and the conclusion was the integrity of the MSAC-14 well was acceptable.