bluuebunny/crossref_metadata_2025 huggingface dataset:
Operational Experience Using Acoustic Reflectometry to Detect Blockages in Gas Pipelines
Authors: Wang Xuesong , Lennox Barry , Short Gordon
Published: February 2011

This paper will provide an overview of a novel acoustic reflectometry method that has been developed to detect features, such as blockages and leakages in industrial gas-filled pipelines. The basic concept of the technique is to inject a pulse of sound into a pipeline and then measure the reflections produced as this signal travels along the length of the pipe. Wherever the cross sectional area of the pipeline changes, such as points of partial or full blockage, there will be a reflection produced. By measuring these reflections and using knowledge of the speed of sound in the gas, the location of any features in the pipeline can be identified. The technique is non-invasive and can be used remotely to accurately detect many pipeline features, such as holes, blockages and other objects including valves and even girth welds.

The paper will present the results from laboratory tests and field trials which will show the accuracy of the technique in detecting and locating blockages and valve status in industrial pipelines containing high pressure gas. In particular details of a test where the method was used to locate an obstruction in a live offshore pipeline containing high pressure will be provided. The difficulties associated with detecting abnormalities in industrial gas pipelines will be discussed and suitable signal processing methods will be described which should enable the technique to be applied as a continuous monitoring tool for offshore gas pipelines.
Investigation of Anisotropic Behavior of Montney Shale Under Indirect Tensile Strength Test
Authors: Keneti S. A. , Wong R. C.
Published: February 2011

Located in a large area spanning the British Columbia and Alberta border, the Montney shale formation is one of the largest economically feasible resource plays in North America. Hydraulic Fracturing is one of the stimulation methods to enhance the gas production in which fractures induced by hydraulic loading are created. Initiation and propagation of hydraulically induced fracture is controlled by in-situ stresses magnitude and orientation and the reservoir tensile strength. If the in-situ stresses composing one vertical and two horizontal stresses are comparable or lie within a narrow range, the tensile strength becomes one of the most important parameters in governing hydraulic fracturing of the reservoir. This paper develops different point and line load tests to determine the tensile strength of Montney shale cores in two perpendicular directions. Test results indicate that Montney shale exhibits a high anisotropy in tensile strength. The tensile strength in the horizontal direction is dominated by the bond strength of the intact structure whereas that in the vertical direction is controlled by the existence of the natural beddings (foliations). This paper also addresses how this anisotropy in tensile strength could affect the pattern of hydraulically induced fractures in the field.
Natural Fracture Characterization From Microseismic Source Mechanisms: A Comparison With FMI Data
Authors: Williams-Stroud S. , Kilpatrick J. E. , Eisner L. , Cornette B. M. , Neale C.
Published: February 2011

Microseismic monitoring of hydraulic fracture stimulation is used to map the extent of fracture growth during the completion of unconventional resource wells. Usually the geometry of the event distributions is used to infer fracture plane orientations, for instance when microseismic events are concentrated along a particular azimuth. Often the induced microseismicity is the result of reactivation of existing fractures in the reservoir. Source mechanism analysis that allows identification of the specific fracturing behavior of individual microseismic events can aid differentiation between reactivation of existing fractures and the creation of new fractures. This paper presents the results from the microseismic monitoring of a Mid-Continent horizontal gas shale well where failure planes of source mechanisms from the microseismic events are compared with fractures identified in a resistivity image log. The source mechanisms originate from failure on existing fracture planes, many of which the image log show to be partially or completely healed. The reactivation of these fracture planes are the dominant failure mechanism detected by the monitoring, but additional fracture planes were also likely stimulated by the treatment but seismicity associated with other fractures has a signal to noise ratio below that required to invert for source mechanisms. Enhanced production resulting from the stimulation is expected to result from a combination of fractures in the natural fracture network; those related to the source mechanisms and other fractures that may be opened aseismically. The result is a well-connected fracture network because of contributions of flow from multiple fracture orientations.
Investigating the Expected Long-Term Production Performance of Shale Reservoirs
Authors: Vassilellis G. D. , Li C. , Seager R. , Moos D.
Published: February 2011

There is worldwide interest in the development of shale plays: North America has attracted noteworthy investments, while other continents are ready to follow that example. Besides the increasing commercial significance of shale plays, traditional volumetric and material balance approaches that are used for petroleum asset evaluation fail to address the special attributes of such formations, or they cannot rely on measurable and practical input. The current practice is to statistically analyze historical records in developed areas and to apply the derived type curves in new areas by assuming performance similarity. Provided that there is a sufficient statistical record base, the assumption of similarity is challenged by the multitude of parameters influencing performance. These tend to differ, introducing considerable uncertainties into predictions. As the advanced drilling and fracture stimulation techniques were introduced in the last decade, historical records support only the early production history, while late performance is extrapolated without many reference points to match.

This paper investigates the applicability of traditional and non-traditional empirical, analytical and numerical methods that are used to predict shale well performance. The goal is to rationalize the link between natural/stimulated rock description with oil and gas recovery mechanisms in a way that is practical at various scales of resolution and covers early and late times. The authors have investigated the application of performance analysis techniques that are fit for macroscopic view and numerical methods that describe multiple mechanisms at a much higher level of resolution. Special features such as flow through fracture networks, gas desorption and geomechanical effects are incorporated in numerical simulation in a way that relates to the measurable petrophysical and geophysical input. Although the application of such macro- and micro-analysis has been examined within only a few case studies, it is suggested that future work would test and improve the application of these shale engineering principals. In retrospect, this study offers an understanding of mechanisms and limitations that can be used for optimization, or for the scaling-up results from a certain area to other areas that differ in natural attributes and may also adopt different design and operational practices.

The simulation exercise reported in this paper represents an idealized situation and it should not be inferred that this can be used to indicate recovery from any specific shale reservoir or well, which would require additional study and appropriate incorporation of practical data that were not available to the authors in the public domain.
Mixing of an Oil Shale With Inert or Reactive Media to Avoid Decarbonation at the Passage of a Combustion Front
Authors: Sennoune M. , Salvador S. , Debenest G. , Mourzenko V.
Published: February 2011

Description of the material

Ground oil shale semicoke was prepared in a laboratory retorting furnace under inert atmosphere. A laboratory combustion cell was then used to operate the combustion of the semicoke added with more or less sand and/or carbonates. This enabled to vary independently the amount of CaCO3 and the amount of fixed carbon in the mix. The temperature of the combustion front propagating in this mix was recorded, together with its velocity. The flue gas was analysed.

Application

Propagating a combustion front through a fixed bed is a way to produce oil and a fuel gas from oil shale or to recover energy from oil shale semicoke in the retort process. When operated with air, this process involves high temperatures - typically larger than 1000C□B0C -resulting in the decarbonation of the carbonate matrix and the emission of additional CO2. The aim of this work was to avoid this decarbonation.

Results, Observations, and Conclusions

It is shown that increasing the amount of CaCO3 in the medium (with constant fixed carbon amount) can decrease the combustion front temperature down to 800C□B0C but not below, which is not sufficient to avoid decarbonation. Decreasing the amount of fixed carbon can decrease the temperature down to 600C□B0C, a temperature at which decarbonation occurs only a bit. At this temperature, not all the oxygen in the fed air is used, which results in a slowing down of the combustion front.

Significance of Subject Matter

To our knowledge, no results have been published yet where the two parameters of carbonate amount and fixed carbon amount were varied independently, and where their impact on the front temperature and decarbonation were determined. Avoiding decarbonation in such processes is a potential very significant way to reduce CO2 emissions.
Petrophysical Characterization of the Eagle Ford Shale in South Texas
Authors: Mullen J.
Published: February 2011

The Eagle Ford shale play is an emerging shale play that extends from the Mexican border in south Texas all the way to the East Texas Basin. Developing the play into an economically viable venture encompasses numerous challenges to include:

The shale production characteristics vary across the play. The shale is producing dry gas in some areas and wet gas or oil in others. Some regions are naturally fractured, while others are not. The play must be hydraulically fractured to be economically productive; however, what completion techniques have been successful in one well will not necessarily work in another, even in the same field. Thus, it is critical to consider the local-area reservoir characteristics when trying to complete each well.

This paper focuses primarily on understanding the reservoir by integrating various data-acquisition and reservoir-characterization techniques (i.e., mudlogs, basic openhole logs, and advanced logs, such as Dipole sonic, geochemical, NMR (magnetic resonance-imaging log), and core analysis) to determine the shale's petrophysical characteristics and to thus build a locally validated petrophysical model (shale log) that can be applied to future wells with reduced data-acquisition programs to grade the reservoir. The model is used to ascertain the surrounding lithology and clay typing in addition to the hydrocarbon resource potential of the well. Furthermore, this tool can be used to answer completion questions, such as where the organic-rich zones are located, where to perforate, what the geomechanical issues are, how "fracable" the rock is, and how plastic the rock is.
A New Method for Production Decline Analysis of Tight Gas Formations
Authors: Shahamat Mohammad Sadeq , Aguilera Roberto
Published: February 2011

A new method for evaluation of production decline analysis of a single well in a tight gas formation is presented. The approach is inspired by practical observations from the Cadomin (Lower Cretaceous) and Nikanassin (Upper Jurassic) formations in the Western Canada Sedimentary Basin (WCSB). The Cadomin is encased sometimes in formations of low or ultra-low permeability, which feed the Cadomin, enlarging significantly the ultimate gas recovery (2 to 3 times) of the well and leveling out the gas production rate. The gas feeding can occur through isolated spots due, for example, to the presence of an unconformity.

The proposed method solves the continuity and flow equations for Cadomin-equivalent gas reservoirs and the encasing low and ultra-low permeability formations, which might correspond, for example, to tight or shale gas reservoirs. The new mathematical solution permits integrating the rates at which the well is producing and the rates at which the low or ultra-low permeability source is feeding the Cadomin-equivalent reservoir. Equilibrium is reached when the contribution from the low or ultra-low permeability reservoir is equal to the rate contributed by the Cadomin-equivalent to the wellbore. The proposed method is flexible enough to allow situations in which a higher permeability source might feed a tighter reservoir connected to a wellbore.

The method has application on different types of production declines, for example Arps exponential, hyperbolic and harmonic declines; and more recently developed techniques such as the power law method. The goal of the model, however, is not to replace any of the conventional approaches, which have their place in decline analysis of specific reservoirs, but rather to supplement them on the basis of practical observations that integrate geology of tight gas formations and gas production rates. In the proposed method we get away from Arps’ empirical exponent, b, which has been used (that is good) and abused (that is not good) in the past.

It is concluded that the method developed in this study has application in most types of production declines, including linear and bilinear flow. The solutions are illustrated with actual production rates from tight gas formations in the Western Canada Sedimentary Basin.
The Effect of Heterogeneity on the Character of Density-Driven Natural Convection of CO2 Overlying a Brine Layer
Authors: Farajzadeh R. , Ranganathan P. , Zitha P. L. , Bruining J.
Published: February 2011

The efficiency of mixing in density-driven natural-convection is largely governed by the aquifer permeability, which is heterogeneous in practice. The character (fingering, stable mixing or channeling) of flow-driven mixing processes depends primarily on the permeability heterogeneity character of the aquifer, i.e., on its degree of permeability variance (Dykstra-Parsons coefficient) and the correlation length. Here we follow the ideas of Waggoner et al. (1992) to identify different flow regimes of a density-driven natural convection flow by numerical simulation. Heterogeneous fields are generated with the spectral method of Shinozuka and Jan (1972), because the method allows the use of power-law variograms. We observe from our simulations that the rate of mass transfer of CO2 into water is higher for heterogeneous media.
Characterization of Leakage through Cap-Rock with Application to CO2 Storage in Aquifers - Single Injector and Single Monitoring Well
Authors: Zeidouni M. , Pooladi-Darvish M.
Published: February 2011

The geological storage of carbon dioxide provides the possibility of maintaining access to fossil energy, while reducing emissions of carbon dioxide (CO2) to the atmosphere. One of the essential concerns in geologic storage is the risk of CO2 leakage from the storage formations. Leakage occurs through possible pathways in the seal, which include a) transmissive faults, b) abandoned wells (penetrating the entire seal or part of it), c) active wells that partially penetrate the seal, d) and local seal weakness and fractures.

CO2 leakage to the subsurface formations can adversely affect the existing and potential energy and mineral resources and shallow ground water resources and soils. As such, detection and characterization of CO2 leakage pathways from storage formations into overlying formations is necessary. The target aquifer could be tested for the leakage pathways before CO2 storage. This will allow for the determination of proper storage aquifers and locations for the injection wells. In this work, we suggest a flow and pressure test and present an inverse methodology to detect and characterize leakage pathways based on the pressure data.

The flow test is based on the injection (or production) of water into (or from) a storage aquifer at a constant rate. The pressure is measured at a monitoring well in an aquifer overlying the storage aquifer, which is separated by an aquitard. The objective of the test is to locate and characterize any leakage through the separating aquitard. The interpretation method is based on forward and inverse solutions of a new analytical model presented in an earlier work. We present an inverse procedure to obtain the leakage pathway transmissibility and location, based on the pressure measurements in an observation well completed in the monitoring aquifer. Inversion analysis is utilized to evaluate the capability of leakage parameters’ estimation through pressure monitoring.
Experimental Study of Capillary Effect in CO2 Solvent Extraction Process for Oil Sands
Authors: Rabiei Faradonbeh M. , Harding T. G. , Dong M. , Abedi J.
Published: February 2011

Bitumen may be separated from oil sand in surface mining operations by using an anhydrous process in which oil sand is mixed with a low boiling solvent such as naphtha. While the majority of bitumen is removed from the sand there is a residual amount of bitumen that remains on the sand and this residue also contains some of the solvent used in the process. It is important to effectively recover as much of the solvent trapped in the spent solids as possible. After most of the bitumen-solvent mixture has been removed from the sand, pressurized CO2 can be used as an anti-solvent to displace residual solvent in the spent sand bed.

In this study, an experimental investigation is made of the effect of capillary force to enhance solvent recovery by mechanical separation, before proceeding to CO2 extraction. Using a thin, semi-permeable layer can facilitate drainage of the solvent from coated sand by capillary force. The results indicate that by using a micro filter the solvent saturation in the sand can be decreased to about half of solvent saturation achievable without using a membrane. It is also possible to further decrease the solvent saturation in sand by pressurizing the air above the sand bed, but it is a slow process.

This experimental study suggests that higher efficiency can be obtained by this simple method and that it has potential to reduce the amount of CO2 required for the next step of solvent recovery by gas extraction.
Multiphase Flow Measurements Sensitivity Assessment and Management - A Cost Effective Methodology for Surveillance Engineers and Field Operators
Authors: Sherief Mohamed , Al-Hassani Khaled K. , Al-Ameri Ammar F. , Abdou Medhat K.
Published: February 2011

Multiphase flow measurements (MPFM) have gained the oil and gas industry focus since the early 90’s(1) due to its continuous improved performance and ease of remote operations (1). Different MPFM systems have been developed but none of them can be referred to as absolutely accurate (3). One of the commonly used systems combines Venturi meter with gamma ray fraction meter (4). The latter is simple, robust and extremely accurate for a given composition based on physical measurements. However, the sensitivity of the nuclear attenuation to heavy atoms can lead to drastic uncertainties on Water Liquid Ratio (WLR) measurements. Therefore, applications where heavy atoms composition changes with time represent an operational and economical shortcoming for surveillance engineers and field operators due to the need to frequently update the configuration data set of such MPFM systems every time the wellstream composition changes.

This paper provides surveillance engineers and field operators with a methodology that has been developed and validated while commissioning new permanent MPFM units on three major onshore fields in the UAE. Several sensitivity studies were carried out to determine the impact of lumping well configuration profiles into groups and assess the MPFM measurements sensitivity to various physical and compositional flow parameters such as phase densities, viscosities, %H2S, %CO2 and water salinity. It also offers a cost effective solution in order to optimize the time and cost required for initial and/or frequent MPFM configuration work by introducing pre-determined configuration data sets that takes into account the wellstream compositional variation with time.

The suggested methodology was applied on 247 wells producing from five different reservoirs. It has significantly reduced the man-hour required to complete the individual well profile configuration from 60 days to 8 days. Once the methodology is implemented, it requires no further vendor support and no frequent physical reconfiguration. For MPFM systems that do not rely on nuclear attenuation technology, the methodology still can be applied to identify measurements sensitivity envelope to any physical, chemical and/or mechanical parameters.
Geomechanical Modeling for Wellbore Stability during Drilling Nahr Umr Shales in a field in Petroleum Development Oman
Authors: Al-Wardy Widad , Urdaneta Oscar Portillo
Published: February 2011

Drilling through Nahr Umr shales has been a challenge in many fields in North of Oman due to the weak nature of these shales. Increased difficulty is faced during drilling if the knowledge of the geomechanical parameters is limited especially the in situ stress magnitude and direction in the formation drilled. Problems such as borehole collapse and stuck pipes cause major delays in drilling time due to borehole cleaning and sidetracking in this specific field. This time delay and other recovery measures undertaken has cost huge amount of money that can be significantly reduced if the geomechanical parameters such as rock strength and in situ stresses of Nahr Umr are known. This can be then used to obtain the appropriate mud weight to drill a well in any desired direction in order to minimize borehole failure.

The geomechanical properties of Nahr Umr shales across North of Oman are not very well covered. Unfortunately acquiring such data always comes last on the list of the petroleum engineers due to lack of awareness of the importance of such data in appropriately calculating the drilling parameters. This specific field had some good data obtained through lab and field measurements that can be used in building a geomechanical model. This included parameters such as unconfined compressive strength of the rock (UCS), Poisson’s ratio, Young’s modulus, and in situ stress magnitude and direction. These parameters were used to build a geomechanical model for Nahr Umr shales for this specific area. This model was then used as input in wellbore stability analysis tool. The same geomechanical model can be used for Nahr Umr shale in any near by area if there isn’t any data available for that specific area however for more accurate analysis it is always better to acquire data for the area of interest.

In this paper some problems during drilling the Nahr Umr shales will be discussed. Also, the workflow of building a geomechanical model in order to use it in wellbore stability analysis will be described. The output results will summarize the minimum required mud weight and unconfined compressive strength (UCS) for drilling a well in any direction in a form of lower hemisphere plots.

The preferred direction for drilling inclined well through Nahr Umr shales in this field was found to be in the maximum horizontal stress direction (SHmax) which is the NE-SW direction. Drilling in the minimum horizontal stress direction (Shmin) which is perpendicular to SHmax was found to be more risky for which mud weight has be raised to avoid borehole failure.

Understanding the geomechanics in this field, in addition to other drilling practices, has contributed in reducing well delivering times from 36.8 days on average in 2009 to 30.1 days in 2010 to date, mainly due to reduction in borehole failure related problems.
Horn River Frac Water: Past, Present, and Future
Authors: Pond J. , Zerbe T. , Odland K.
Published: February 2011

An uninterrupted economical supply of frac water is critical to the successful development of the Horn River Devonian shales. and Apache have progressed our water supply from tank truck delivery of fresh surface waters to an integrated, subsurface saline water treating and distribution system. The current system is designed to deliver water at a rate of 16 m3/min to a maximum daily volume of 16,000 m3 or enough water for 3–4 fracs per day. This presentation will discuss our experiences with fresh surface waters, the design and implementation of the pilot plant and the design, construction and operation of the full scale sour water processing plant. Another aspect that will be discussed are the water source wells including geology, drilling, completion and high volume lift systems.
Lessons for Environmental Compliance From One Company's Creative Sentencing Case
Authors: Bowen F. , Van der Byl C. , Dillabough J. , Bertels S.
Published: February 2011

In this paper we describe a creative sentencing research project that arose from infractions at an oil sands in situ facility. We briefly outline some root causes of the infractions, key features of the industry context at the time, and lessons for regulatory compliance. While there were some contextual factors such as general industry turbulence, regulatory uncertainty related to a new technology and an industry wide personnel shortage that contributed to the conditions that resulted in these infractions; we also identify more fundamental causes of the compliance failures in this case. We find that a weak management of change process, weak operational compliance tracking and a weak culture of compliance were all at the root of this particular failure. We stress the importance of building a culture of compliance, viewing compliance as a journey and managing the cognitive load of compliance as important elements in ensuring compliance.
Applications of Micro and Nano Technologies in the Oil and Gas Industry-An Overview of the Recent Progress
Authors: Kong Xiangling , Ohadi Michael M.
Published: February 2011

Micro and nano technologies have already contributed significantly to technological advances in a number of industries, including the electronics, biomedical, pharmaceutical, materials and manufacturing, aerospace, photography, and more recently the energy industries. Micro and nano technologies have the potential to introduce revolutionary changes in several areas of the oil and gas industry, such as exploration, drilling, production, enhanced oil recovery, refining and distribution. For example, nanosensors might provide more detailed and accurate information about reservoirs; specially fabricated nanoparticles can be used for scale inhibition; structural nanomaterials could enable the development of petroleum industry equipment that is much lighter and more reliable and long-lasting; and nanomembranes could enhance the gas separation and removal of impurities from oil and gas streams. Other emerging applications of micro and nano technologies in the petroleum industry are new types of "smart fluids" for enhanced oil recovery (EOR) and drilling. In short, there are numerous areas in which nanotechnology can contribute to more efficient, less expensive, and more environmentally sound technologies. This paper provides an overview of the micro and nano technologies with a particular focus on nanotech-based solutions for the oil and gas and the broader energy industry. Recent developments in research in areas of significance to the oil and gas industry are briefly reviewed and include two case study examples. The potential opportunities and challenges that face future trends of nanotechnology applications in the oil and gas industry are also discussed.
Lattice-Boltzmann Method to Estimate Relative Permeabilities for Matrix-Fracture Interaction in Naturally Fractured Reservoirs
Authors: Gunde Akshay , Babadagli Tayfun , Mitra Sushanta K.
Published: February 2011

Oil production, enhanced oil recovery, waste disposal, and CO2 storage applications in naturally fractured oil, gas, coalbed methane, geothermal reservoirs, and aquifers are characteristically controlled by an interaction between matrix and fracture. The correct estimation of the relative permeabilities for matrix-fracture interaction is essential in the performance analysis of such reservoirs. Conventional relative permeability measurement techniques are not suitable for this type of processes as the driving force is capillary rather than viscous. An alternative to these techniques is a pore scale modeling of the process. In this study, matrix-fracture interaction by capillary (spontaneous) imbibition was numerically simulated using the Lattice Boltzmann Method (LBM). The classical LBM algorithm was modified to add the effects of capillary characteristics such as wettability and interfacial tension. The model was validated using experiments on two - dimensional sand pack models, where the strongly water-wet model saturated with oil was exposed to water to displace oil by capillary interactions. Further, LBM simulations were used to investigate the critical parameters that have impacts on relative permeabilities such as different wettabilities, matrix boundary conditions that cause co-current interaction, and gravity (vertical and horizontal interaction). Finally, the LBM results were used to generate relative permeability curves by incorporating the algorithms based on single – phase normalization techniques. The LBM images were used to quantify the saturation values. The effects of different parameters listed above on the end points and the shape of the relative permeability curves as well as the residual oil saturation were identified. The results and observations provide qualitative and quantitative data which can be used in modeling studies for naturally fractured oil, gas, and coalbed methane reservoirs.
Extended-Reach Drilling - One Run to TD
Authors: Gagigi T. , Balslev Peter V. , Hardie Jamie , Isevcan Erhan , Cockburn Colin
Published: February 2011

The development strategy for Qatar’s offshore Al Shaheen field involves a large number of extended-reach horizontal wells with total depths (TDs) ranging from 20,000 to 40,000 ft measured depths (MDs). Since the 2005 field development plan was initiated in May 2006, about 3 million ft of productive footage has been drilled. Drilling performance and tool reliability have been consistent challenges but have been improved to levels that enable the drilling of most sections in one bottomhole assembly (BHA) run to TD.

This paper reviews the changes made to increase drilling efficiency and to reduce non-productive time, including analysis of drilling performance for each hole section and subsequent improvement strategies. Discussions encompass the systems and processes contributing to the improvements.
The Significance of Accurate Well Placement in the Shale Gas Plays
Authors: Kok Jeffrey , Moon Brad , Han Shim Yen , Tollefsen Edward , Baihly Jason , Malpani Raj
Published: February 2011

Unconventional shale gas reservoirs are known for low porosity, low matrix permeability, the lack of an obvious seal or trap, large regional extent, and, in most areas, are believed to be highly heterogeneous in nature. As a result, it is common practice to confirm the reservoir thickness, evaluate the shale gas rock properties and to determine horizontal shale gas targets using vertical or pilot offset wells. Horizontal wells are then drilled and stimulated to maximize reservoir exposure and enhance inflow production performance.

Taking advantage of the high gamma ray activity found in most shale plays, a majority of horizontal wells are steered to stay within the defined target window using a non-azimuthal, averaged gamma ray measurement only. By relying on a single measurement, there is no fall back when the interpretation presents several possible scenarios. Additionally, a non conclusive interpretation will negatively impact the efforts of optimizing the learning curve across a field.

Resistivity measurements complement gamma ray data as they provide an extra data set for correlation. However, azimuthal images from density measurements acquired in real time can offer structural dip authentication along the well trajectory to provide a higher level of accuracy to the modeled structure. By having a validated structural model, a higher level of confidence in real-time steering decisions can be gained. An accurate structural model is also an effective tool to aid completion designs, correlate formation properties, refine target delineation and provide a foundation for evaluating production logs and microseismic observations.

The main objective of this paper is to demonstrate how structural modeling using only gamma ray in horizontal wells can lead to non-unique solutions that can be a potential cause of inconsistent reservoir interpretations and varied production, not only between hydraulic fracturing stages but also from well to well. Having sufficient measurements for formation evaluation, drilling and production results can be better understood and applied to enhance target selection, followed by accurate well placement within the selected target structure. This level of well placement accuracy will deliver consistent production results and provide a common platform for evaluating completion practices.
Tight Gas Multi-stage Horizontal Completion Technology in the Granite Wash
Authors: Edwards W. M. , Braxton Daniel K. , Smith Vince
Published: February 2011

The Granite Wash formation is a tight gas reservoir comprised of several, independent, productive horizons in the western Anadarko Basin. Each productive interval can be up to 400-ft. in certain areas. Historically, the entire 3,000-ft. package of these multiple, thick, clastic wedges has been drilled as a vertical well asset with the intent to commingle the multiple productive zones within the upper and lower intervals. Recent efforts to drill horizontal wellbores in preferential zones within the Granite Wash package have proven to be a viable exploitation alternative.

Most of the available completion technologies have been implemented with varying success, and a better understanding of reservoir performance has been linked with an increase in fracture stage capacity to drive the evolution of completion methods.

This paper exclusively addresses horizontal, multi-stage completions. Open hole, packer isolated completions as well as cased hole, perforated completions were analyzed to determine the best method of stimulation in the Granite Wash formation. Twenty-five wells drilled over the course of the last three years were analyzed with roughly half of the sample wells being open hole and the other half being cased hole.

The Granite Wash is currently considered one of the highest rates of return plays in the continental U.S. The best manner of completing these wells is subject to debate and highly controversial. The data presented in this paper demonstrates the relative success of the most common methods used and gives a recommendation for future success.
Successful Contracting of Production Facilities for Al Shaheen Field, Offshore Qatar
Authors: Cheesebrough J. S. , Messaoud Younes Ben
Published: February 2011

In 1992 Qatar Petroleum signed an Exploration and Production agreement with Maersk Oil Qatar AS regarding the development of the Al Shaheen field offshore Qatar. Production commenced in 1994 via early production facilities, and by late 2005, when 18 permanent platforms had been installed through earlier field development plans, the Field Development Plan 2005 (FDP 2005) was initiated.

FDP 2005 required 15 additional platforms (with a total dry weight of 125,000 tonnes), 24 inter field pipelines (with a total installed length of 240 Kms) and 5 subsea power cables (with a total installed length of 50 Kms) to be installed and connected offshore with the existing platform facilities in full production and executing a 6 rig, 163 well drilling campaign at the same time. In addition to prepare the existing facilities for the integration with the new FDP 2005 facilities, approximately 4 Million man hours of Brownfield work was required. The overall offshore work was completed with a production “up time” of 99.7%, Remarkable.

Personnel safety and environmental protection are essential and constant considerations within Maersk Oil Qatar and therefore the safety performance of FDP 2005 was a source of great satisfaction; more than 55 Million construction man hours were expended on the project, both onshore and offshore, without any fatalities and with an achieved overall LTIF of less than 0.3.
ESP Runtime Optimization - Low Volume High GOR Producers
Authors: Al-Aslawi Raed , Al-Haimer Mohammad Salem , Zahedi Alireza , Al-Khonaini Talal A. , Al-Najim Abdulaziz
Published: February 2011

A limitation of Electrical Submersible Pumps (ESPs) is the inability to handle significant volumes of gas. The implications of this limitation become even more critical if the fluid production rate is at or below the minimum rate required for cooling of downhole equipment. The oldest and most widely practiced method for forced convection cooling of the motor of an ESP system is to use a motor shroud. However, numerous field case studies have shown that even with the motor shroud in place, motor failure has been the primary cause of ESP failure in low-volume high-GOR wells.

The optimal mitigation solution for low-volume high GOR cased-hole producers is to lower the ESP string below the perforations, with a shroud installed for cooling of the motor. For low-volume high-GOR ESP-equipped producers that are producing from an open-hole interval installation of the same conventional shrouding system would take care of the cooling of the motor but it will not function as a free gas eliminating or reducing device. The production strings of the ESPs producing from an open-hole interval usually include an inverted shroud intended to reduce the amount of free gas entering the pump. Such installations would not function as a motor cooling device.

The large degree of production loss and the increased operating cost incurred by unplanned ESP shut-down and failure have been two of the major challenges faced by the asset teams of South Fuwaris (SF) and Humma (HUM) Fields in PNZ-Kuwait, in their efforts to maximize the uptime of low-volume high-GOR ESP-equipped open-hole producers. A customized shrouding system was needed to simultaneously resolve the issues of motor cooling and the reduction of the amount of free gas entering the pump. The dual functioning nature of a shrouding system composed of a conventional shroud combined with an inverted shroud was the main feature that had to be incorporated in the design of such system.

Through the continuous efforts of the South Fuwaris and Humma asset teams, a novel dual-shrouding system has recently been developed to fulfill the requirements of cooling of the motor and reduction of free gas entering the pump simultaneously. Multiple customized versions of this system have been installed in critical low-volume high-GOR open-hole producers since the 4th quarter of 2009.

Examination of historical operating conditions of ESP strings equipped with the new shrouding system showed a significant reduction in the number of ESP shut-downs due to underload, overload or high motor temperature trips, and a dramatic drop in the number of ESP failures caused by overheating of the motor.

This paper discusses the benefits of the newly-designed shrouding system and its built-in perforated tail pipe, specifically designed for low-volume high-GOR producers in South Fuwaris and Humma Fields, and actual results achieved from field implementation of this system.
The Interactive Plant Model, A New Approach to Facilities Integrity
Authors: Sharaf Omar
Published: February 2011

This paper presents a comprehensive guide to creating, viewing and editing a 3-D panoramic model of any facility. The model allows the user to easily interact with the different units within the facility by simply clicking on them. An average user who has never been to the facility could become familiar with the plant in a few clicks of a button. The model manages to incorporate operating envelopes, technical integrity reports, P&IDs, operating manuals, procedure guides, unit descriptions, daily reports and HSE specifics in a user friendly fashion. This allows newcomers and experts to communicate and share information easily while minimizing chances of error. Such a model could be installed and downloaded on a network to manage information, collect historic data, manage changes and follow up plant activities.
Wellhead Compression on Tight Gas Wells in the Long Run: A Follow-Up Case History on Seven Years of Success in Lobo
Authors: Harms L.K.
Published: February 2011

Many times lowering surface pressure results in production increases on tight gas wells but how does that increase hold up in the long run and what is the rest of the story on wells that originally did not show increases? A previous paper (SPE 90550) detailed results at the start of a long range program to install wellhead compression (WHC) in ConocoPhillips' Lobo Field in South Texas. Updated data showing the long term results over seven years on the original 21 wells are presented as well as results and lessons learned from over 40 additional installations. Based on these experiences, a general approach toward choosing candidates and operating wellhead compression on tight gas wells is proposed.
Improved Flaring Technology: High Pressure Air Assist System for Smokeless Flaring
Authors: Mashour Mazen , Smith Scot , Palfreeman Nigel , Seefeldt Greg
Published: February 2011

In order to meet increasingly strict environmental regulations and to promote cleaner energy at their facilities, many oil, gas, and petrochemical companies are seeking to upgrade existing flares to allow smokeless flaring of hydrocarbon gases. Poor public perception of existing smoking flares increases the difficulty of operations, so upgrading systems to smokeless operation minimizes the environmental impact and improves local acceptance in urban areas. The main areas of application for these flare upgrades are harsh environments located in Russia, Africa, Middle East, South America, and other countries with high oil production capabilities and programs. Many of these areas have utility flares located in facilities where a shortage of steam or water prevents conventional smokeless steam-injection systems from being added. A new technology is needed for these kinds of applications.
Acid Effect Life Cycle in Carbonate Reservoir, Field Case
Authors: Al-Marzouqi Mariam , Al-Farisi Omar , Amer Mohamed Mostafa , Serry Amr , Yammahi Fatmah
Published: February 2011

In one of the biggest carbonate reservoir in offshore Abu Dhabi that has been producing oil for more than 40 years, oil potential evaluation is affected by many uncertainties as evaluated via pulsed neutron technology across perforated intervals.

The Acid used to stimulate the wells after workovers affect the responses of the pulsed neutron logs. Efforts have been exerted to eliminate this effect. Observations from this field showed that the acid life cycle in the formation can be extracted by comparing and correlating several pulsed neutron sigma logs that are acquired over the years across the same perforated intervals.

It has been noticeable that one of the most influential parameters in removing or eliminating acid existance in reservoir rock is water production, otherwise acid effect on pulse neutron sigma log interpretation remains, resulting in calculating high water saturation across dry oil producing zones.

Understanding this acid effect life cycle helped understanding reservoir performance and reducing uncertainty of pulse neutron sigma interpretation. This paper is showing these observations in our field and is detailing acid effect modeling on pulsed neutron log responses.
Estimation of Fracture Properties for a Horizontal Well with Multiple Hydraulic Fractures in Gas Shale
Authors: Aboaba A. , Cheng Y.
Published: February 2011

Pressure transient well testing is an important tool for evaluating well performance and reservoir characteristics. However, conventional pressure transient test often becomes impractical to wells in shale gas reservoirs due to the nature of extremely tight shale formations.

This study presents a new method for estimating fracture properties for a horizontal well with multiple hydraulic fractures in shale gas reservoirs. The method analyzes commonly available production rate and pressure data to provide reliable estimates of both fracture half-length and formation permeability. The method first converts variable rate-pressure data into an equivalent constant-rate pressure drawdown test, and then pressure transient analysis techniques are applied for property estimates.

Our new approach is primarily based on analysis of linear flow dominated data for estimates of both matrix permeability and fracture half-length. It doesn’t require the existence of the elliptical flow or the appearance of the pseudo-radial flow for independent estimate of matrix permeability. This is very important because we can estimate the properties from early-time production data for horizontal shale gas wells. Synthetic cases are presented to validate the proposed method and demonstrate its applicability.
Conventionally Undrillable Open Fractured Reservoir, Successfully Drilled Using Managed Pressure Drilling Technology in Algeria
Authors: Hamoudi B. , Kartobi K. , Qutob H. , Arnone M. , Torres F. , Murray C. , Barakat N.
Published: February 2011

The Field was discovered in 1960 during the exploration phase, this field is located between the Hassi Messaoud field and Rhourd de Nouss Central Field in the Triassic Basin in Algeria. The field represents many challenges for conventional drilling due to the complexity of the geological structures, one of these is the Hamra Quartzites formation; a gas reservoir sandstone highly tectonically fractured. The drilling history of this formation shows events of total fluid losses leading to gas kicks due to the loss of hydrostatic head in the annulus.

A 6″ hole section in NZ-XX well was planned to be drilled under the Constant Bottom Hole Pressure (CBHP) technique, throughout the Gres de Ouargla and the Hamra Quartzites formations; bounding the drilling window by the estimated formation pressure as lower limit, and the fluid losses pressure (hydrostatic pressure of mud used in offset wells) for the upper limit, both estimations were done at the top of the reservoir. The drilling window for Managed Pressure Drilling-MPD was validated by determining the Bottom Hole Pressure where both, an influx from the formation and fluid losses occurred. These values were later used to establish the target Equivalent Circulating Density-ECD to drill the hole accordingly.

The ECD management was achieved by controlling both, the surface back pressure and the annular out-flow; monitored in real time. The Bottom Hole Circulating Pressure-BHCP changes recorded in a Pressure While Drilling-PWD tool, placed in the Bottom Hole Assembly-BHA.

As the drilling progressed, fluid losses were experienced and instantaneously controlled by reducing the ECD. Despite the lower and upper MPD window limits converged, drilling continued managing losses as no open operating range existed. As a contingency for this scenario, switching to the Flow Drilling technique (UBD) was proposed and planned, but due to environmental restrictions, flowing the well while drilling was not possible. The MPD operations in NZ-XX successfully achieved 191 meters of open hole; then TD was called due to a combination of increasing losses – gas influx conditions and increasing risk of total losses in the underlying Hamra faulted structure.

This paper describes in detail the successful MPD application which is considered a start he drilling technology to enhance Nezla field exploitation. Lessons learned and challenges encountered will also be discussed in this paper.