bluuebunny/crossref_metadata_2025_split huggingface dataset:
Combining The Micro Grain Imager With The Effective Medium Theory For Quick Assessment Of The Absolute Permeability In Carbonates
Authors: Abbad Mustapha 
Published: April 2012

Abstract
In this paper we suggest a method for a quick indication of the absolute permeability for carbonate rock using the effective medium approximation (EMA) and pore size distribution obtained from 2-D images. A pore network is built from modified cubic lattices. Instead of using the well-known coordination number for cubic lattices, z = 6, a new correlation between z and the normalized pore radius is suggested for both sandstone and carbonate formations. The imaging of the rock sample is obtained by using a new tool called Micro Grain Imager (MGI) which works with visible light emitted through a scanning probe inserted in a drilled hole in the rock sample. An area of 12.5 x 37 mm2 of sidewall of the hole is obtained with a resolution of 25 mm. Processing the acquired images allows for obtaining the pore diameter and pore shape factor distributions. The hydraulic radius approximation is used to determine the pore conductance needed to predict the absolute permeability. When compared to the measurements done with conventional core measurements, our model provides better estimation for intermediate and high permeability than the predictions by the existing EMA models and the values obtained from the usual empirical formulas. This makes the effective medium approximation, our coordination number model, and the micro grain imager a powerful combination that can be used in the laboratory or surface measurement in the field. The combination provides the field engineer with a straight forward method for characterizing the rock.
Integral Pod Intake for Electrical Submersible Pumps
Authors: Rooks Mark K. , Snyder Kristopher , Wilson Lyle , Fleming James , Mack John , Wisnewski Matt 
Published: April 2012

Abstract
Electrical submersible pumping (ESP) system performance is limited by the amount of free gas that could be tolerated before gas-locking would occur. Gas-locking of a pump generally causes a catastrophic failure of the ESP system because the pump no longer is moving fluid, which keeps the ESP from overheating during normal operation. Understanding of the phenome-non of head degradation and gas-locking in a pump is well known and has been documented and presented in numerous SPE papers in the past.
The net result of excessive gas at the pump intake is that the gas can potentially accumulate into a long continuous column in the pump, impeding the pump's ability to generate discharge pressure. Gas-locking occurs when the pump is unable to lift the fluid column in the tubing above. In cases where the pump does not actually gas-lock, at the very least the pump will suffer head degradation and low efficiency when high vapor-to-liquid ratios are being pumped. Due to the impact of free gas by volume on ESP performance, the industry has made extensive efforts to address this problem. Two important approaches have been developing technology that either separates the gas from the fluid prior to entering the pump inlet, or creating gas handling pumps which can pump larger gas by volume percentages of up to 70 percent before pump head degradation and gas-locking occurs.
Within Saudi Aramco, ESP applications have become a major contributor to meet our artificial lift requirements. In these applications, Saudi Aramco has avoided the potential issues that occur when free gas is present at the pump inlet by ensuring the pump intake pressure remains above the bubble point pressure of fluid being produced. Although this mode of operation has prevailed thus far; it is anticipated that an ever increasing number of applications will see the presence of gas at the ESP intake. Additionally, one of the leading causes of ESP failures within Aramco is directly attributable to the electrical system consisting of the packer penetrator, motor lead cable, and motor pothead.
To address these challenges, Saudi Aramco has collaborated with Baker Hughes to develop the integral pod intake (IPI) system. The IPI system is a new patent-pending concept initiated by Saudi Aramco that incorporates the shroud hanger for an encapsulated pod system as part of the intake, constructed as a single assembly including the seal, electrical penetrators, and electrical conduits extending to the seal base. This paper will discuss the background and development of the IPI system in terms of how it addresses the issues that occur when free gas is present at the ESP pump. The system's ability to eliminate the electrical integrity problem between the packer and motor pothead will also be covered. A field trial is planned to begin this year in Saudi Arabia and the results will be made available for the 2013 ESP Workshop or in earlier publications within SPE.
A Case Study for the Application of Type Curves for Production Data Analysis of Shale Gas Wells with Linear Dual Porosity Behavior
Authors: Abdulal Haider J. , Lyngra Stig , Wattenbarger Robert A. 
Published: April 2012

Abstract
In recent publications, it has been observed that shale gas wells behave like a linear dual porosity system. In this paper, a linear dual porosity model is utilized assuming matrix rock as the main primary porosity that feeds a hydraulic fracture, which acts as a secondary porosity system and primary flow conduit. The paper demonstrates the practical application of the type curve analysis method for shale gas and shale oil published by Abdulal, Samandarli and Wattenbarger (2011). The technique utilizes the actual well performance to obtain a type curve match that allows determination of the parameters required to quickly determine the completion/fracture effectiveness and allow projection of the long-term well production performance.
In this paper, the ideal application of the type curve method with calculation procedures is presented with two actual field examples. Field Case 1 demonstrates the type curve matching followed by the procedure used to calculate dual porosity parameters like effective fracture permeability, drainage volume and the area of the interfaces between the hydraulic fractures and the rock matrix. These parameters can be used to evaluate the well completion with its associated hydraulic fracture effectiveness. Field Case 2 is included to illustrate the method limitations and potential pitfalls when applying this type curve approach.
Optimization of Downhole Sand Screens by Lab Studies in Multiple Gas Fields
Authors: Al-Rabeh Majed. N. , Al-Mohanna Khalid S. 
Published: April 2012

Abstract
A lab study was conducted to evaluate the performance and optimize different sand screen sizes currently being run in Saudi Aramco Gas Fields. The study was inclusive of three phases, Phase (I) was to analyze the retention capability of the different sand screen sizes against formation core samples from Gas Fields-A, B, C and D. Phases (II) and (III) were mud filter cake permeability damage/clean up tests in "Well bore collapse" and "Open annulus" scenarios respectively. For all three phases, different sizes of premium sintered meshes were selected along with a wire wrap screen.
With regards to sand retention capabilities in the specified gas fields, only the 200μ and 310μ premium mesh screens passed the sand retention criteria. Furthermore, there was no strong indication on which screen size is superior to the other. It was concluded from the study, that the 310μ premium mesh screen is the optimium screen for fields A and D as it provides slightly higher retained permeability values when compared to the 200μ screen. Moreover, the study indicated that permeability damage resulting from the deposition of filter cake residue on the screen can have a negative impact on the retained permeability of the screen. A significant increase in screen retained permeability was achieved once the filter cake was removed with an average increase of approximately 23%. Also, by using performance master curve predictions, it is believed that the 350μ premium mesh screens will not provide satisfactory sand retention in fields B and D.
This paper highlights the successful application of a laboratory sand control evaluation and optimization study conducted on screens being run in Saudi Aramco gas fields. In addition, performance master curves were used to predict the performance of an additional premium mesh screen size against formation samples from the specified gas fields.
A New Practical Approach To Evaluate Near Wellbore Formation Damage Parameters Based on Well Test Analysis for Gas Reservoir
Authors: Kome Melvin , Amro M. M. , Hossain M. M. 
Published: April 2012

Abstract
Prediction of degree of near-wellbore damaged caused during drilling and completion is extremely difficult and challenging in any reservoir development program. It plays a vital role on decision making, specifically when the decision has to be made based on inflow performance relationship (IPR) analysis. Skin factor used for most of the IPR models are either calculated from analytical models depending on the near wellbore conditions (e.g. open hole, perforated, gravel packing etc.); or predicted based on expensive well test data. While accuracy of the predicted results depends on the accuracy of input parameters available to feed into model, nevertheless this approach can generate range of uncertainties with misleading predicted results that significant effect on decision making.
This paper presents a simplified practical method of estimating the extent of damage and amount of skin in a reservoir. Correlations for the permeability in the damage zone have been developed as a function of the average reservoir permeability in the drainage area of reservoirs for steady, stabilized or transient flow conditions. The model uses well deliverability test data to predict average permeability in the drainage zone. The model has been applied to different cases using representative field test data for high and low permeable reservoirs. It has been demonstrated that the proposed model exhibits very good approximation of damage components affecting reservoirs.
From this analysis, it could also be concluded that by using data from unsteady flow deliverability tests, it is possible to get a good estimation of the damage skin in a reservoir and its extent. This is valid as long as the damage does not exceed the transient drainage radius. Exceeding the transient drainage radius will imply deriving very large skin values from the test, and this is rare in most cases.
A Review of Recent Developments and Challenges in Shale Gas Recovery
Authors: Arogundade O. , Sohrabi M. 
Published: April 2012

Abstract
Over the past decade, there has been increased interest in shale gas plays worldwide. This is due to improved techniques in shale gas recovery from these ultra-low (in the order of hundreds of nanodarcies) permeability formations which is owed primarily to horizontal drilling, hydraulic fracturing and other technological advances. Another attraction to the exploration of shale gas is the lower inherent risk associated with its exploration when compared with exploring for conventional hydrocarbons due to its ubiquitous abundance wherever it is present. This success has indeed driven down gas prices and has culminated in the security of gas supply worldwide for decades to come.
This paper is a critical literature review of shale gas that identifies and examines challenges encountered in shale gas recovery which include inadequacies in mathematical flow models applied in shale gas modelling due to non-darcy flow, uncertainties in the fracture intensity, fracture symmetry and orientation and lack of standard protocols to mention a few. It also takes a look at how hydraulic fracturing improves the economics of shale gas exploitation since it considerably increases production and also the overall recovery from the reservoir. Hydraulic fracturing has come as the primary mode of increasing recovery in shale gas reservoirs but it also comes with its own problems where desired results are easily achieved in brittle shale formations but may be even more challenging for ductile shale formations. Another progress made is being able to monitor the fracture growth within the reservoir real time to prevent the fracture growing out of control.
Milestones are continually being achieved on improving the recovery of shale gas and in this paper we address progresses made and challenges encountered.
Improved Technology Enhances Gas Production and Decreases Cost In Underbalanced Drilling While Using Coiled Tubing Directional Drilling
Authors: Ahmed Kashif , Kirby Cliff , Law Alasdair , Al-Humood Malik 
Published: April 2012

Abstract
Drilling re-entry wells with the highest expected production and least possible cost is always the aim of operators. The biggest challenge in gaining maximum reservoir contact when drilling with underbalanced coiled tubing drilling (UBCTD) is when it reaches lock up depths, resulting in weight transfer issues to the bit and reduced reservoir contact. Factors affecting this are formation, well profile, tortuosity, etc. These issues can be mitigated by using a rib-steered motor (RSM), with which it is possible to increase lateral reach by drilling smoother wellbores.
One technique is to thoroughly define the primary objective of the well, during the pre-planning stage, not only to increase hydrocarbon recovery, but to improve wellbore quality and minimize tortuosity which helps to achieve a greater reservoir contact. Using underbalanced coiled tubing drilling grants access to new gas-bearing formations in reservoirs that were previously by-passed or missed.
The authors present the advantages of using a 3-in. RSM compared to a 2⅞-in. conventional motor, with the help of a case study comparing all RSM and conventional motor runs. It also compares rate of penetration using RSM and 2⅞-in. conventional motor and how it affects the occurrence of lockup while drilling.
The paper also details how an underbalanced well in the Middle East for a large operator using the 3-in. RSM managed to complete the well in 24 days, some 18 days ahead of schedule for the Approval for Expenditure (AFE). The same well was also characterized by a number of drilling records that included the longest footage in a 24 hr period and the longest-ever run drilled since UBCTD was introduced. This increased performance can largely be credited to the revolutionary technology that the RSM brings to coiled tubing drilling (CTD), enabling wells to be drilled faster, with significant benefits in reach, steering ability and greater reservoir contact.
Identifying New Opportunities in a Mature Reservoir: Wara Formation, Wafra Field, Saudi Arabia/Kuwait Partitioned Zone
Authors: Masarik Cristina , Gonzalez-Mieres Ramon , Jamil Farhan , Buza John 
Published: April 2012

Abstract
The giant Wafra Field is the largest field in the Partition Zone (PZ) between Saudi Arabia and Kuwait. The Cretaceous Wara reservoir represents one of the most prolific producing zones in the PZ. The Wara is a Cretaceous sequence of channel sands (fluvial/tidal) that have locally complex vertical and a stacking patterns. These sands are interpreted to have been deposited in a tidally influenced lower delta plain depositional environment in a low angle ramp setting characterized by low accommodation space. Stratigraphic complexity is high and in general, sandstone bodies are below seismic resolution. The Wafra Wara reservoir is a structural accumulation formed by a low amplitude anticline with 4-way dip closure, with some structural complexity at the reservoir level, consisting of normal faults with small displacements.
Although the Wafra Wara clastic reservoir is mature, new "sweet spots" with original formation pressure were drilled recently in the middle of the development area, and there is also still significant remaining oil on the current margins of the field where deeper OWCs have recently been encountered. Increasing water cut and an active aquifer present some challenges to maintaining good oil production in the reservoir, mitigated by production optimization efforts and a rigorous surveillance program.
A comprehensive multidisciplinary study was performed to identify new infill well and workover opportunities within the most mature portion of the field to increase production and recovery. The team reviewed all existing data and performed detailed 3D-seismic interpretation to refine stratigraphy and structure, generate production attribute maps and to understand the production history and current state of the reservoir. Production, well-test data, cased-hole logs and analytical techniques were used to identify areas with by-passed oil and to predict initial rates and incremental recovery for infill wells. Deterministic and probabilistic forecasts were generated using field and offset well decline curve analysis. New opportunities were then ranked based on geological and engineering criteria.
This paper highlights the challenges and lessons learned from this integrated reservoir management study to define remaining oil and to identify opportunities to increase ultimate recovery.
Real-Time Database Inventory Model, KPI and Applications for Intelligent Fields
Authors: Khan Farooq A , Muhawes Hamad 
Published: April 2012

Abstract
The real-time data under the Intelligent Field concept is gathered from different pieces of equipment, such as permanent downhole monitoring systems (PDHMS), electric submersible pumps (ESP), chokes, multiphase flowmeters (MPFM) via multiple sensors installed at the wells, plants and flow-lines. In the future, the real time monitoring systems will be installed in the majority of Saudi Aramco fields. The high frequency raw real-time data received from the subsurface smart well completions and MPFM at the surface represents a unique system that did not exist before.
Coordinated joint efforts started a few years ago under Phase-1 to develop the Real-Time Inventory Model and Applications to load and retrieve real-time data. The model and applications covered the real-time equipment mapped with corresponding sensors and tags. After the real-time inventory model was created, another process started mapping and loading each piece of equipment and the real-time data from the sensors through the tags assigned to each sensor.
Phase 2 incorporated all enhancements to the real-time inventory applications related to Key Performance Indices (KPI) data entry and reporting system. This action was required to keep the real-time inventory database as the single source for reporting monthly KPIs to the senior management. New real-time applications in the corporate database were developed to give the Intelligent Field users the facility to review and display all equipment, sensors and tags and to provide quality control of the real-time data. This has eliminated duplicate data entry in two systems (KPI Excel Sheets and real-time data entry) and consequently saves valuable time and effort by the production engineers. This change has also enabled better data quality control and assurance.
The benefits of the new system include real-time data loading from equipment, validating and maintaining equipment inventory in real time, tag standardization, application development for the KPI system, and providing engineers’ desktops with an uninterrupted flow of raw and summarized real-time data.
A Procedure for Measuring Contact Angles When Surfactants Reduce the Interfacial Tension and Cause Oil Droplets to Spread
Authors: Adejare O. O. , Nasralla R. A. , Nasr-El-Din H. A. 
Published: April 2012

Abstract
Viscoelastic surfactants (VES) are used as diverting agents in carbonate matrix acidizing. However, these surfactants can adversely affect wettability around the wellbore.
Receding contact angles were measured to study the effect of spent acid solutions with an amphoteric amine-oxide VES, and the mutual solvent EGMBE on the wettability of Austin cream chalk rocks. However, when oil droplets are injected into spent acid solutions with VES and EGMBE, low oil-acid interfacial tensions (IFT) cause them to spread on the rock surface. Contact angles cannot be measured when droplets spread. In addition, spreading may result from low oil-acid IFT's, rather than indicating strong oil-wetness.
A procedure is proposed for contact angle experiments for surfactant solutions that cause oil droplets to spread. Rocks were centrifuged in spent acid solutions with VES and EGMBE. Then, contact angles were measured in spent acid with HCl only, to prevent VES and EGMBE from reducing the oil-acid IFT. The effect of the surfactants in the spent acid on the rock-oil/acid IFT, which is the wettability, is shown by the difference in contact angles before and after centrifuging.
Using the proposed procedure, a spent acid solution with HCl, 1 vol% VES and 10 vol% EGMBE made an oil-wet rock water-wet, and a water-wet rock strongly water-wet at 25°C. This suggests that an EGMBE postflush enhances the relative permeability to oil, under the parameters investigated.
Contact angles are a function of the rock-oil/acid and oil-acid IFT's. The wettability of the rock is determined by the rock-oil/acid interface. The proposed procedure is effective because, in contrast with the conventional procedure, the oil-acid IFT is kept high and constant, so that changes in the rock-oil/acid interface can be observed. The proposed procedure will be used in future studies of the effect of spent acid solutions with VES and EGMBE on wettability.
Simultaneous Determination of Capillary Pressure and Relative Permeabilities
Authors: Hashmet Muhammad R. , Tan Isa M. , Majidaei Saeed , Mushtaq Muhammad 
Published: April 2012

Abstract
Simulation of multiphase flow in porous media requires knowledge of relative permeabilities. Such data can be obtained from laboratory experiments, either steady state or un-steady state methods. Steady state experiments are time consuming, and can run over several days to acquire a complete set of relative permeabilities. Unsteady state methods are limited to displacements where the assumptions underlying the Buckley-Leverett theory is satisfied and capillary pressure must be ignored. Capillary pressures are generated where interfaces between two immiscible fluids exist in the pores (capillaries) of the reservoir rock. Due to the interfacial energy of the interface between the two phases, a difference in the pressure across the interface results in a curvature of the interface. It is usual to consider one phase as a wetting phase and the other as a non¬wetting phase. However, intermediate cases occur which can greatly complicate the picture. In this paper a simultaneous determination of relative permeability and capillary pressure was achieved from the results of a single two phase flow experiment using Sendra Software. By using this software a first simulation was performed and then the results were history matched using core flood data. The core flood experiment is a standard imbibition or drainage displacement with an imposed difference in pressure. A four-step core-flooding scheme provides the differential pressure across the core, production data as a function of time, injection rates from which the relative permeabilities and capillary pressures are computed for both drainage and imbibition by Sendra. Finally the capillary pressures and relative permeabilities were compared using different correlations available in the software. After comparing the different correlation for relative permeabilities and capillary pressure the best correlation was selected for each.