bluuebunny/crossref_metadata_2025 huggingface dataset:
How Advances in Technology can Help Safely Abandon Off-Shore Subsea Wells
Authors: Segura Richard , Haq Mohammed A.
Published: April 2012

At some point, an oil or gas well inevitably shifts from asset to liability, whether the result of reaching its economic limit, sustaining irreparable damage or being a disposable exploratory well. At the end of its life cycle, a well must be plugged and abandoned (P&A); while adhering to regulatory and environmental standards, its supporting infrastructure must be carefully dismantled to ensure that it poses no safety or environmental threats and any useable components salvaged to help defray costs. In addition to creating significant safety and environmental hazards, failure to properly abandon a well can lead to a noncompliant status with regulatory agencies and undermine an operator's image. Despite its multiple liabilities, abandonment offers no real return on investment (ROI), underscoring the importance of minimizing cost while still ensuring a safe and regulatory compliant operation. One of the main challenges is to retrieve the wellhead without damage so that it can be used again.

Clearly wells in onshore or shallow water offshore environments present little difficulty in accessing the wellhead and carrying out the required P&A operations. However the most challenging wells to P&A are deepwater wells where the wellhead is located on the ocean floor often at considerable depth so that physical access to it is infinitely more challenging. In this subsea environment there exist two different approaches to the problems associated with well abandoned and wellhead recovery. These involve internal cutting of the surface and conductor casings combined with either internal or external latching of the wellhead.

In this paper the authors will review these two different approaches, comparing their viability and describe in detail the external latching system which offers some distinct advantages in the P&A process. They will go on to provide some detailed case studies which illustrate its’ successful use in various deepwater offshore operations.
State-of-the-art Openhole Shale Gas Logging
Authors: Franquet Javier A. , Bratovich Matt W. , Glass Richard D.
Published: April 2012

Faced with increasing field maturity and production decline from conventional gas reservoirs, oil companies are shifting their focus and pursuing new alternatives; one of them being the development of shale and gas plays. To be economically viable, these low-permeability formations require fracture stimulation. Interval selection within shale reservoirs for hydraulic fracturing or horizontal laterals are based on several variables: sufficient organic matter or total organic carbon (TOC) and favorable hydraulic fracturing stimulation. The presence and extent of the natural fracture system can also influence the performance of a shale reservoir; therefore, natural fractures should be characterized within the shale formation not only from wireline or LWD borehole images logs but also from cross-dipole deep shear wave imaging which can illuminate fractures up to 60 ft away that do not intersect the well. To assess these aspects, a mineralogical, structural, and geomechanical characterization of the shale formation should be conducted. The mineralogical characterization and TOC quantifications mainly rely on a pulsed neutron spectroscopy and nuclear magnetic resonance (NMR) logs. The processing of capture and inelastic gamma ray spectra obtained from the pulsed neutron tool quantifies the formation's basic elemental composition, including silicon, calcium, aluminum, iron, sulfur, magnesium, and carbon. Geomechanical characterization is based on acoustic and density log responses. Variation in the reservoir mineralogy and TOC content affect the rock mechanics properties. Stress vs. strain curves can be derived from a micro-mechanical model of the rock which enable correlations between dynamic (obtained from acoustic logs) and static elastic properties (obtained from triaxial compression testing on core samples). Additionally, the azimuthal and transverse shear wave anisotropies are processed from cross-dipole acoustic logs to characterize the vertical and horizontal rock stiffness. This anisotropic characterization of the rock enables the evaluation of the fracture gradient and stress contrast between the target formation and the overlying and underlying formations. The paper focuses on the interaction between mineralogy, organic content and geomechanical analyses in shale gas reservoir evaluation.
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

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

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

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

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

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

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

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

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

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

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

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.
Heavy Oil Viscosity Measurements; Accuracy, Reliability, and Repeatability
Authors: Alkandari Hassan , Alomair Osamah , Elsharkawy Adel
Published: April 2012

The aims of this work is to present consistent and reliable viscometer measurements for heavy oil samples and to draw a comprehensive comparison amongst the several viscosity measuring procedures for the same solo crude oil sample. Viscosity measurements were preformed for temperatures over the range of 25°C to 80 °C with three apparatuses. These apparatuses include an Oscillating Piston Electromagnetic Viscometer (OPV), Rotational Rheometer using Cone and Plate (RCV), and Oscillating U-tube of rotating concentric cylinders (OUV). More than 36 heavy dead oil well head samples were collected from different Kuwaiti fields to perform this study. The API gravity of oil samples collected, ranges from 13 to 23 degrees with a good assortment of composition. It was concluded that each viscosity measurement is environment as well as apparatus operational principle limited. These expected errors in laboratory-measured oil viscosity are the main factors in the degradation of the oil viscosity correlation equation's efficiency. Homogenized sample aliquots are analyzed at various test conditions; hence corresponding data is precisely collected. The measurements are verified and assured by the National Institute of Standards and Technology (NIST) tractable Standard Referenced Materials.
Anisotropy and True Formation Resistivity Measurements with a New LWD Resistivity Sensor
Authors: Bittar Michael , Wu Hsu-Hsiang , Li Shanjun , Bayrakdar Mohammed
Published: April 2012

The determination of true formation resistivity is always a challenging component of oil field exploration. The electromagnetic (EM) resistivity tool, one of the most well-known logging tools, provides geological information by detecting electrical properties of the formation downhole. Accurate geophysical knowledge assists petrophysicists to develop a better reservoir and to enhance oil production. However, it is often critical to know the hydrocarbon saturation, which requires reliable horizontal and vertical formation resistivities. During the last decade, wireline triaxial induction logging has successfully provided resistivity anisotropy in vertical wells, whereas logging-while-drilling (LWD) azimuthal EM tools have demonstrated similar field results in deviated wells with only high relative dip angles. Low dipping drilling conditions have posed difficulties regarding conventional LWD measurements for resistivity anisotropy determination because of simple antenna structures.

This paper describes the development of a new LWD EM resistivity sensor that uses an antenna configuration with tilted transmitter and receiver antenna orientations rotated relative to the borehole by rotary steerable drilling. Measurements made by this antenna configuration are obtained by unique processing schemes that enable the determination of the dip angle, strike angle, and vertical and horizontal resistivity of the formation at any relative dip angle while drilling. The paper discusses the design concept of the sensor and the environmental parameters that influence tool responses.

Several test results, with data processing and the inversion schemes, are shown and compared to various resistivity logging tools. These results indicate that the new LWD EM resistivity tool provides reliable conventional resistivity readings and determines resistivity anisotropy and dip at any relative dip angle. The paper also highlights additional discussions about the calculation of anisotropy and dip angle and about related applications using the sensor.
Dependency of Remaining Oil Saturation on Wettability and Capillary Number
Authors: Abeysinghe Kumuduni Prasangika , Fjelde Ingebret , Lohne Arild
Published: April 2012

Wettability is a major factor that affects the flow behavior and recovery efficiency in oil reservoirs. In this study, the effects of wettability on water-oil relative permeability (kr), capillary pressure (Pc) curve and capillary desaturation curve (CDC) have been investigated in laboratory on core scale.

Water floods and surfactant floods at different capillary numbers (Nc) were carried out in sandstone rock at different wettability conditions. These floods were followed by oil floods. The kr and Pc curves were estimated by history matching the experimental production and pressure drop.

The recovery after water flood was higher at non water-wet conditions but a higher throughput of water was needed. Estimated kr and Pc curves vary with the wettability of the rock. The relative permeability of the wetting phase is more curved than that of the non wetting phase. The measured CDC for oil in mixed-wet condition and the CDC for water in water-wet condition deviate from the typical CDC shape. In these cases, it is found that the measured remaining oil or water saturation is a function of the number of pore volumes injected and also it is largely affected by capillary end effects. Since the residual saturation is difficult to be obtained in core floods at non water-wet conditions, the measured CDC in laboratory experiments does not represent the true CDC. More focus should be directed at relative permeability (corrected for capillary end effects) than the residual oil saturation.

The results presented in this paper demonstrate the importance of the wettability of rock on recovery efficiency and also the importance of correcting the laboratory data especially predicting the flow behaviour of non water-wet conditions. Remaining oil saturation based on relative permeability should be used instead of residual oil saturation in evaluation of the potential for tertiary recovery, e.g. surfactant.
A New Viscoelastic Surfactant for High Temperature Carbonate Acidizing
Authors: Wang Guanqun , Nasr-El-Din Hisham A. , Zhou Jian , Holt Stuart
Published: April 2012

Diverting agents have been widely used during matrix acidizing treatments to accomplish the uniform distribution of acid solutions across the target zones. One of the most popular formulas is based on viscoelastic surfactants (VES) which showed good results in the lab and field tests. A major limitation with the conventional VES is temperature. Most of these surfactants do not hold viscosity at temperatures greater than 250°F.

A new VES that can be used at higher temperatures was developed. The apparent viscosity of the spent VES-based acids was measured as a function of temperature and shear rate at 300 psi. Various corrosion inhibitors were mixed together with the new VES to find out the most compatible formula. A coreflood test was conducted on a 20 in. long carbonate core to examine the performance of the new surfactant. The core was CAT scanned before and after the experiment to observe the wormholes created by the new system. The acid contained 20 wt% HCl and 4 vol% VES.

Spent acids of the new VES had a high viscosity up to 325°F. Several corrosion inhibitors were identified that can be mixed with the new system without affecting the apparent viscosity of the spent acid. Similar to current VES, mutual solvent is recommended in the post flush to reduce the fluid viscosity and remove any gel from the core. CAT scan of the core show wider and tortuous wormholes, indicative of good retardation of the new VES-based acid system.
Improved Understanding of Proppant-Formation Interactions for Sustaining Fracture Conductivity
Authors: Rayson Neelam , Weaver Jim
Published: April 2012

A recent paper published data describing interactions between shale and commercial ceramic proppants. It reported that the diagenetic outgrowth materials formed were zeolites. The creation of these zeolites was reported to largely depend on the characteristics of the formation mineralogy and the fluid medium. It was further reported that when tested under dynamic conditions, these diagenetic-type reactions were not observed. The standard API crush test was used to indicate the percentage of fines generated.

This paper presents the results of extensive laboratory testing with sandstone and bauxite proppants at moderate reservoir temperatures and normal reservoir pH in which dramatic loss of proppant-pack permeability and proppant strength were observed. Zeolites were identified and responsible for much of the fines material created during the testing cycle. Zeolite deposits were also detected, even when bauxitic proppants were aged in the aqueous fluid medium alone. In both cases, the fluid medium was DI water, which is not a source of any metallic element. These results indicate that zeolite formation is also dependent on the chemistry of the proppant. Similar results have been reported for tests conducted under dynamic flow conditions. It is crucial to ensure that the true value of proppant strength degradation is determined; however, it is questionable that the API conductivity testing procedure is the best method.

This paper presents repeatable data generated from laboratory tests at reservoir temperatures, as well as at elevated temperatures, that indicate conditions under which zeolites are formed and the effect on proppant strength degradation using both single-grain crush-strength analysis and the API conductivity procedures. This data provides better information for the proper selection of proppant for given formation conditions.
Forecasting and Monitoring Water Cut Utilizing ESP Pump Discharge Pressures and Fluid PVT Analysis
Authors: Al Enezi Sultan M. , Warlick Mickey L. , Almusabeh Muzher I. , Kaba Abdullah A.
Published: April 2012

In some fields, the ability to obtain reliable water production numbers is hard to do. Case in point is one Saudi Aramco offshore field. This particular field has all wells on electrical submersible pumps (ESPs) and has supervisory control and data acquisition recorded real time. Oftentimes the timing of getting the samples to shore, the lab, and to the desktop of the engineer takes a very long time. By modeling and using the pressure-volume-temperature (PVT) data from the reservoir and the pump discharge pressure of a well we can determine what water cut is necessary to match the surface flowing wellhead pressure (also taking into account frictional losses). Utilizing this method allows Saudi Aramco to monitor water production in the field and then to verify it with actual water samples whenever the data becomes available.
Stimulation Strategies to Guard against Uncertainties of Carbonate Reservoirs
Authors: Bukovac Tomislav , Nihat M. Gurmen , Jauregui Jairo Leal , Malik Ataur R. , Bolarinwa Simeon , Al-Ghurairi Fadel
Published: April 2012

Due to the complex nature of carbonate reservoirs, reservoir characterization often leaves many uncertainties. Finding the right balance between risks associated with these uncertainties and optimum stimulation makes acid fracturing and matrix acidizing treatments challenging. The stimulation objectives become even more difficult in highly slanted, layered, naturally fractured reservoirs exhibiting high permeability contrast. In this environment, adequate fluid diversion and leak-off control have always been the key design elements for stimulation. Achieving diversion and leak-off with a degree of control to make treatments applicable to a wide range of reservoir uncertainties presents challenges.

A novel, polymer-free degradable diversion system has been in use for the last three years in the largest carbonate reservoirs of the world, namely the Khuff formation in Saudi Arabia's Ghawar field. The self-diverting fluid combines viscoelastic surfactant in HCl with degradable fiber technology. The fluid develops viscosity as the acid spends, while the fibers bridge across perforation tunnels and fissures to form a filter cake. Because the fibers completely degrade with time and the spent fluid breaks when it comes into contact with hydrocarbons or solvents during flowback, the fluid temporarily limits injectivity into thief zones without damaging the reservoir.

More than 50 wells have been stimulated with this fluid system covering a wide range of single and multi-stage matrix acidizing and acid fracturing treatments. The controllable nature of diversion from well to well and on-the-fly adjustment capabilities of the fluid system have successfully ensured stimulation performance despite the uncertainties of carbonate reservoirs in Saudi Arabia. In essence, this novel fluid became the standard insurance policy for stimulation treatments of carbonate formations where the permeability models are inherently underestimating the contrast due to difficulties of placing natural fractures and quantifying their impact.
Preparation and Characterization of Colloidal Gas Aphron based Drilling Fluids Using a Plant-Based Surfactant
Authors: Nareh`ei M. Arabloo , Shahri M. Pordel , Zamani M.
Published: April 2012

Colloidal gas aphron (CGA) based drilling fluids, because of their non-coalescing nature, excellent capability in minimizing deep invasion, and also behaving like a flexible bridging material, are indicated for drilling permeable and fractured formations. Their unique feature is to form a solid free, tough, and elastic internal bridge in pore networks or fractures to minimize deep invasion by means of air microbubbles, which can be removed easily during the initial stage of production.

CGA based fluids combine certain surfactants and polymers to create the system of microbubbles. Surfactant is used to produce the surface tension to contain the aphron as it is formed, build the multilayer bubble wall, and create interfacial tension to form a non-bonding network capable of bridging openings in permeable and fractured formations. Polymer is used as viscosifier and aphron stabilizer. The surface activity and aggregation behavior of the surfactant affects the stability and also other physico-chemical properties of generated microbubbles. Therefore, selection of a suitable surfactant is important for the generation of microbubbles with the desired rheological and filtration properties.

The goal of this paper is to investigate the potential use of a new plant-derived surfactant as an aphronizer surfactant in preparation of CGA based drilling fluids for accomplishing desirable rheological and filtration properties. For this purpose, natural surfactant obtained from leaves of special tree namely Zizyphus Spina-Christi and used for preparation of aphron-based fluids. To evaluate the potential use of new plant-derived surfactant as an aphronizer, various physico-chemical properties of aphron-laden muds were investigated. To achieve the research objectives, laboratory tests of suspension generation, microscopic visualization, initial yield, filtration loss, and rheological behavior with varying concentrations of surfactant and polymer were performed.

Effect of base fluid viscosity and surfactant concentration on size/size distribution of microbubbles, rheology, and yield of CGA based drilling fluids will be presented. Three rheological models, namely, Bingham Plastic, Power Law and Casson models were used for characterizing rheological properties of the muds studied.
Transient Pressure Analysis of Gas Wells in Unconventional Reservoirs
Authors: Wu Yu-Shu , Wang Cong , Ding Didier
Published: April 2012

Unconventional gas reservoirs have shown the potential to be the next world primary energy resource and have received a lot of attention in the past few years in the world. Even with the significant progress that has been made world-wide towards commercial development of natural gas from these unconventional resources, understandings or modeling tools of gas flow in these extremely low-permeability reservoirs are far behind the industry needs. In this paper, we present a numerical model for modeling transient gas flow behavior and its application to well testing analysis in unconventional gas reservoirs. Specifically, the numerical model simulates realistic reservoir gas flow processes, including Klinkenberg effect, non-Darcy flow behavior, and adsorption under reservoir flow condition, in addition to wellbore storage and skin effect. We use the numerical model to generate various type-curves for nonlinear gas flow for well testing analysis in unconventional porous and fractured reservoirs and demonstrate the conventional well testing analysis approach may still be applicable for analysis of unconventional gas reservoirs.
Effect of Acid Gas on Cement Sheath Integrity: Experimental Findings
Authors: Garnier Andre , Laudet Jean Benoit , Patil Sandip , Patil Rahul , Ravi Kris , Ferreira Luis
Published: April 2012

Long-term cement sheath integrity is important to maintain wellbore stability and effective zonal isolation. Various factors influence cement sheath integrity, such as effective placement of cement, mechanical and thermal stresses, and interaction with corrosive gases. Corrosive gases are known to chemically attack Portland cement. However, the challenge is designing a cement system that can sustain CO2 and H2S attack.

Acid-gas-resistant systems are useful in various applications, including producers and CO2 injector wells. To understand how the cement sheath is affected by prolonged exposure to corrosive gases, detailed studies should be performed at different temperatures and pressure conditions.

This paper documents a resilient cement system that was exposed to CO2 and H2S gas environments for a period of three months. For comparison purposes, a neat cement system was used as a reference and tests were conducted at 194 (90°C) and 284°F (140°C). X-ray density profiles obtained using tomography techniques were used to analyze samples. The cement samples responded differently to CO2 and H2S environments. Formation of CaCO3 on exposure to CO2 was evident and was reflected in X-ray density profiles. Conversely, leaching of neat cement was observed on exposure to H2S gas. In both cases, the resilient cement system specially designed for the work described proved to be a better option when compared to neat cement because the destruction was less prominent in the former case.
Physical activity of male and female adolescents living in a town and a city in the context of public health recommendations
Authors: Mynarski Władysław , Nawrocka Agnieszka , Rozpara Michał , Garbaciak Wiesław
Published: April 2012

Physical activity of male and female adolescents living in a town and a city in the context of public health recommendations

Study aim: To assess the physical activity of male and female adolescents from Poland living in a town (Czechowice-Dziedzice) and in a city (Katowice).

Material and methods: The research involved 431 high school students aged 16-18 years (249 from Czechowice-Dziedzice and 182 from Katowice). Physical activity was measured by the short form of the International Physical Activity Questionnaire (IPAQ). The volume of the different levels of physical activity was calculated in units of MET min/wk.

Results: The total volume of weekly physical activity was higher among high school students living in a town (Czechowice-Dziedzice) than students living in a city (Katowice). Only 31.5% of the students met the criteria for recommended physical activity.

Conclusions: The level of physical activity varies by place of residence. Students living in towns are more physically active than youth living in cities. Most high school students (64%) included in the research can be considered to be insufficiently physically active.