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This paper was prepared for the 43rd Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Houston, Tex., September 29-October 2, 1968. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers Office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. "How to Write a Technical Paper", or "How to Write a Report" make good book titles. The subject is large enough to fill a book and many have been written. And there are several on the broader subject of clear writing. It is not the purpose of this paper to review the many ideas found in books of this type. Several are listed in the bibliography and the serious writing student can make good use of them. This paper is written assuming the reader has a knowledge of English grammar, its parts of speech, and the more important rules of putting those parts together in sentence and putting those parts together in sentence and paragraph form. From this premise them, this paragraph form. From this premise them, this paper will try to demonstrate how to make your paper will try to demonstrate how to make your product more effective. product more effective. WHY WRITE? First of all, let's differentiate reasons for writing from purpose of writing. Reasons for writing might include (1) a willingness to help out your buddy who is program chairman for the local section; (2) the boss wants a company report for the files on that engineering project you've just finished; (3) you want project you've just finished; (3) you want to try to get published in a trade journal; or (4) this is the only way you can get an all-expense-paid trip to the Fall Meeting. What-ever the reason, we have already decided that you (1) have something to say (2) that you know something that no one else knows and (3) that you can impart knowledge to others and make a genuine contribution to the literature in your particular field. The purpose. The only purpose in writing a technical paper is to get an idea across. May be it's to tell others what you have done and how you did it, or to describe a field operation or a unique equipment installation or possibly to summarize a field's producing life in a case history. A paper clouded with long sentences studded with an oversupply of many-syllabled words and dependent clauses just doesn't get off the ground. Scientific language, unless used wisely, compounds the confusion, and your paper becomes hard to read. Then readership paper becomes hard to read. Then readership dwindles and you have failed in your purpose. The audience. A major drilling breakthrough in the laboratory is worthless if it can't be explained to a driller. An idea that isn't understood dies from natural inertia against change.

A pilot-scale test to remove polar and non-polar organics from produced water was performed at a disposal facility in Farmington NM. We used surfactant-modified zeolite (SMZ) adsorbent beds and a membrane bioreactor (MBR) in combination to reduce the organic carbon content of produced water prior to reverse osmosis (RO). Reduction of total influent organic carbon (TOC) to 5 mg/L or less is desirable for efficient RO system operation. Most water disposed at the facility is from coal-bed gas production, with oil production waters intermixed. Up to 20 gal/d of produced water was cycled through two SMZ adsorbent units to remove volatile organic compounds (BTEX, acetone) and semivolatile organic compounds (e.g., napthalene). Output water from the SMZ units was sent to the MBR for removal of the organic acid component of TOC. Removal of inorganic (Mn and Fe oxide) particulates by the SMZ system was observed. The SMZ columns removed up to 40% of the influent TOC (600 mg/L). BTEX concentrations were reduced from the initial input of 70 mg/L to 5 mg/L by the SMZ and to an average of 2 mg/L after the MBR. Removal rates of acetate (input 120-170 mg/L) and TOC (input up to 45 mg/L) were up to 100% and 92%, respectively. The water pH rose from 8.5 to 8.8 following organic acid removal in the MBR; this relatively high pH was likely responsible for observed scaling of the MBR internal membrane. Additional laboratory studies showed the scaling can be reduced by metered addition of acid to reduce the pH. Significantly, organic removal in the MBR was accomplished with a very low biomass concentration of 1 g/L throughout the field trial. An earlier engineering evaluation shows produced water treatment by the SMZ/MBR/RO system would cost from $0.13 to $0.20 per bbl at up to 40 gpm. Current estimated disposal costs for produced water are $1.75 to $4.91 per bbl when transportation costs are included, with even higher rates in some regions. Our results suggest that treatment by an SMZ/MBR/RO system may be a feasible alternative to current methods for produced water treatment and disposal.

ABSTRACT: We implement a damage mechanics model into the particle finite element method to simulate the pre- and post-failure processes of rock slopes. In this computational framework, the stress-driven strain localisation and damage evolution are modelled based on a continuum damage mechanics model; discrete discontinuities like faults are represented as thin continuum layers of equivalent properties; the particle finite element method is used to solve and track the large deformation of rock masses. In the paper, we first present the mathematical formulation of the proposed model and then conduct a thorough validation of our model for simulating damage propagation against well-documented experimental data. We further apply the model to simulate progressive failure phenomena of a naturally faulted rock slope including both the pre-failure degradation and post-failure runout, demonstrating the strong capability of our model in capturing the emergence, evolution and consequences of catastrophic rock slope failure. Our work has important implications for understanding the physical mechanisms driving the progressive destabilisation and catastrophic failure phenomena of faulted rock slopes in nature. 1. INTRODUCTION Landslide phenomena usually involve the movements of a mixture of rock, earth and/or debris downslope (Cruden, 1991), which tend to develop over time through several different stages, from initiation to propagation and to final deposition (Leroueil, 2001). A landslide may exhibit different phases of movements, and one of the most important episodes is the formation of a fully developed slip surface (Hungr et al., 2014), which is often referred to as a failure. Before the failure, the deformation processes are usually controlled by the variation of stresses, showing a progressive destablisation behaviour (Eberhardt, 2008; Leroueil, 2001); during or after the failure, the geomaterials that have undergone a certain degree of stress loss may show a significantly increased mobility, leading to rapid inertia-dominated movements (Hungr et al., 2014). To describe the complex behaviour of geomaterials during these different phases, various approaches have been developed for landslide analysis (Chen, 2007; Denlinger, 2004; Duncan, 1996; Griffiths & Lane, 1999; Savage & Hutter, 1989; Sloan, 2013). For the pre-failure stage, the state of failure has been determined either statically or dynamically: (i) the static stability is mostly analysed using the limit equilibrium method (Duncan, 1996), limit analysis method (Chen, 2007; Sloan, 2013) and strength reduction method (Dawson et al., 1999; Griffiths & Lane, 1999); (ii) the dynamic stability may be assessed by describing the stress-strain relationship of geomaterials under complex conditions (Duncan, 1996), solved using different numerical techniques. As for the post-failure stage involving large deformations, the moving mass is usually characterised by the simplified Navier-Stokes equations for flow-like problems (Savage & Hutter, 1989). These two phases of slope movements (i.e. pre- and post-failure stages) have long been treated separately in geotechnical analyses due to the lack of a unified computational framework for describing the entire landslide process (Soga et al., 2016).

Operating maturing assets poses increasingly complex challenges to operators. Meeting hourly or daily production targets becomes more difficult when wells are more often shut in for e.g. water washes (against salt deposition) or solvent jobs (at asphaltenes deposition). Declining reservoir pressure in turn results in less margin to compensate lost production while topside facilities can put constraints when production GOR and watercut increase at late production life. In a joint industry project of Wintershall, GdF, EBN, Siemens and TNO the applicability of real-time optimization is explored. The problem description, system architecture and initial optimizer results were presented in Linden (2013). This paper presents results of the optimization project and looks ahead to further field realization. The goal of this paper is to demonstrate that production of a mature North Sea gas asset can be optimized taking into account realistic constraints. All wells at this gas asset are intermittently shut in for water washes while daily nominations must be met. It will be shown that the optimization algorithm obeys the constraints and is fast enough for real-time application and thereby ready for field implementation.

In this paper, we will present our work towards designing a control strategy to mitigate wind turbine wake effects by redirecting the wakes, specifically applied to the Fishermen's Atlantic City Windfarm, proposed for deployment within the next few years off the shore of Atlantic City, New Jersey. As wind turbines extract energy from the air, they create low-speed wakes that extend behind them. Full wake recovery to the undisturbed wind speed takes a significant distance. In a wind energy plant the wakes of upstream turbines may travel downstream to the next row of turbines, effectively subjecting them to lower wind speeds, meaning these waked turbines will produce less power. Wakes can be redirected laterally to some degree, though, by applying yaw misalignment to the wake-generating turbine (i.e., not pointing the turbine directly into the wind). Yaw misalignment causes part of the rotor thrust vector to be pointed in the cross-stream direction, deflecting the flow and the wake in that direction. Yaw misalignment reduces power production, but the global increase in wind plant power caused by decreased wake effects creates a net increase in power production. With the increase in power can come an increase in fatigue loads, though, caused by yaw misalignment. However, if misalignment is applied properly, and it is layered with individual blade pitch control, the load increase can be mitigated. To explore the idea of wake redirection, we used high-fidelity computational fluid dynamics. Our computational fluid dynamics simulations predict that when winds are aligned with the row, which is one of two predominant wind directions, wake-redirection control can create a 10% increase in energy capture efficiency. This means that, for a given wind energy plant's electrical generating capacity, if wake-redirection control were employed, turbines could be more closely spaced, thereby reducing the watersheet area of the wind plant. Likewise, for a given watersheet area, the total electrical generating capacity can be increased. In this paper, we discuss the concept of wake redirection through wind turbine yaw misalignment and present our computational fluid dynamics results of the Fishermen's Atlantic City Windfarm project. We also discuss the implications of wake-redirection control on annual energy production and fatigue loads, as well as plans to implement wake-redirection control at Fishermen's Atlantic City Windfarm when it is operational something not done before at a commercial wind plant.

Novel methods for harvesting energy in down hole applications are desired. Specifically, it is hoped that sufficient power can be generated near a hydrocarbon reservoir to operate commercially available well monitoring equipment. Vibration based harvesters are the most likely systems to be developed. The efficiency of such harvesters is highly dependent on the natural frequency of the structural system. To optimize the harvester design, the dynamic properties of the down hole system must be characterized.This paper presents the results of an analytical frequency study undertaken to identify the role axial force effects, annulus fluid geometry, and annulus fluid properties have on the first natural frequency of a production string as the conveyed fluid velocity was varied. The system was modeled using an Euler-Bernoulli formulation and includes a hydrodynamic forcing function to account for annulus fluid effects. The problem was solved in the frequency domain using the spectral element method, which conveniently provides natural frequency information.The results of the study are in-line with previously published studies on analogous systems. It was found that the well annulus geometry, annulus fluid density, and annulus fluid viscosity have a strong role in determining the behavior of the system. Additionally, the axial force, added mass, and viscous effects were found to shift the natural frequency of the system while only axial force and viscous effects cause a shift in the fluid velocity at which bifurcation occurs. These findings, along with the method outlined in this paper, provide a useful tool in the characterization of hydrocarbon producing wells which is a first step towards developing an energy harvesting system.Although the problem of determining the dynamics of a fluid conveying pipe immersed in a viscous fluid has been approached using a shell formulation in the past, to the authors knowledge this is the first time the problem has been solved with a beam formulation.Approved for publication, LA-UR-15-21089. Copyright for this paper have been transferred to SPE.

Effective well integrity practices ensure the protection of people, facilities and the environment from the risk of uncontrolled release of formation fluids throughout the life cycle of a well, so petroleum engineers are always required to ensure well integrity. Part of well integrity is to make sure downhole equipment and barriers are in excellent condition. Identifying the downhole leak source of pressure communication between tubingcasing and casing-casing annuli in any well is a huge challenge for petroleum engineers. Detecting any leak at the early stage is an important key to well integrity management. Two objectives were set in this paper as follows: The first objective is to develop a method that can detect downhole leaks by utilizing only rigless data based on full interpretation and evaluation of different logs in the field: temperature, noise, and corrosion log in different scenarios. The first scenario is shut-in condition while the second scenario is in flowing condition. The flowing condition will be either after bleeding off Tubing-Casing-Annulus or Casing-Casing-Annulus. This approach was implemented in a specific operation order to ensure job success. Also, the corrosion log was run to evaluate the condition of tubing and casing separately. The second objective of this study is to compare rigless approach results with the conventional rig approach for downhole leak detection, which will be completed by statistically analyzing corrosion, temperature, and noise surveys. Moreover, guidelines were set in each step of these surveys to confirm leak occurrence. This objective was achieved through developing a method and program for leak detection. Based on the conducted temperature, noise, and corrosion surveys, the integrated approach identified the leakage zones through the developed module in this report. The obtained results from the rigless approach were almost similar to the rig approach. The only difference between both approaches is that the developed method is more accurate, compared to the rig approach, since it can identify any corrosion or leak depth, while the rig approach will identify only leak zones. The paper will discuss in details the development of this method and its successful implementation in a few selected offshore wells in the same field of the Arabian Gulf.

The upstream oil & gas industry has been contending with massive data sets and monolithic files for many years, but "Big Data"—that is, the ability to apply more sophisticated types of analytical tools to information in a way that extracts new insights or creates new forms of value—is a relatively new concept that has the potential to significantly re-shape the industry. Despite the impressive amount of value that is being realized by Big Data technologies in other parts of the marketplace, however, much of the data collected within the oil & gas sector tends to be discarded, ignored, or analyzed in a very cursory way. This paper examines existing data management practices in the upstream oil & gas industry, and compares them to practices and philosophies that have emerged in organizations that are leading the Big Data revolution. The comparison shows that, in companies that are leading the Big Data revolution, data is regarded as a valuable asset. The presented evidence also shows, however, that this is usually not true within the oil & gas industry insofar as data is frequently regarded there as descriptive information about a physical asset rather than something that is valuable in and of itself. The paper then discusses how upstream oil & gas companies could potentially extract more value from data, and concludes with a series of specific technical and management-related recommendations to this end.

Ensemble optimization (referred to throughout the remainder of the paper as EnOpt) is a rapidly emerging method for reservoirmodel-based production optimization. EnOpt uses an ensemble of controls to approximate the gradient of the objective function with respect to the controls. Current implementations of EnOpt use a Gaussian ensemble of control perturbations with a constant covariance matrix, and thus a constant perturbation size, during the entire optimization process. The covariance-matrix-adaptation evolutionary strategy is a gradient-free optimization method developed in the "machine learning" community, which also uses an ensemble of controls, but with a covariance matrix that is continually updated during the optimization process. It was shown to be an efficient method for several difficult but small-dimensional optimization problems and was recently applied in the petroleum industry for well location and production optimization. In this study, we investigate the scope to improve the computational efficiency of EnOpt through the use of covariance-matrix adaptation (referred to throughout the remainder of the paper as CMA-EnOpt). The resulting method is applied to the waterflooding optimization of a small multilayer test model and a modified version of the Brugge benchmark model. The controls used are inflow-control-valve settings at predefined time intervals for injectors and producers with undiscounted net present value as the objective function. We compare EnOpt and CMA-EnOpt starting from identical covariance matrices. For the small model, we achieve only slightly higher (0.7 to 1.8%) objective-function values and modest speedups with CMAEnOpt compared with EnOpt. Significantly higher objective-function values (10%) are obtained for the modified Brugge model. The possibility to adapt the covariance matrix, and thus the perturbation size, during the optimization allows for the use of relatively large perturbations initially, for fast exploration of the control space, and small perturbations later, for more-precise gradients near the optimum. Moreover, the results demonstrate that a major benefit of CMAEnOpt is its robustness with respect to the initial choice of the covariance matrix. A poor choice of the initial matrix can be detrimental to EnOpt, whereas the CMA-EnOpt performance is near-independent of the initial choice and produces higher objectivefunction values at no additional computational cost.

Currently, many reservoirs in the region approach the end of primary recovery phase where new techniques are needed to enhance recovery. Therefore, the need to optimize oil recovery from the current resources is very well understood by regional oil companies. To enhance oil recovery from current oil resources, field operators need to overcome the forces responsible for oil entrapment. Enhanced Oil Recovery techniques (EOR) introduce new energy into oil reservoirs to reduce the influence of these forces. Most of these resources contain light oil and are considered suitable candidates for either miscible or chemical EOR techniques. The first technique is challenged by the availability of suitable miscible gas. While, chemical EOR techniques are challenges by the high salt concentrations in the maturing oil reservoirs. The high salinity conditions encourage deficiencies in the performance of chemical EOR processes. Therefore, minimizing the effect of in situ salt on the injected chemical would impose tremendous improvement that leads to higher oil recovery. One way to diminish salt effect is to condition the oil reservoirs by injecting a slug of preflush water prior to chemical injection. In this paper, the performance of polymer flooding, after preflush slug, in high salinity reservoir is investigated by numerical simulation means. The injected slugs, both preflush and polymer, are driven by water. The objective is to identify the relationship between preflush, polymer, and drive water characteristics and oil recovery. Seven parameters were considered: preflush slug size, preflush salinity, polymer slug size, polymer concentration, polymer slug salinity, and drive water salinity. The results show that these parameters have various degree of influence on oil recovery. For example, increasing the preflush slug size would results in more oil recovery especially during the early time. Detailed findings will be presented in the paper.

Abstract The main objective of the paper is to create and develop a theoretical modelof spray icing on sea vessels and floating oil and gasexploration&production structures and facilities. The main goodness of fitis particular match of the model's results with vessel records and observationsdata published in special literature. Besides factors affecting the vesselicing are discussed and methodology of their quantitative accounting isproposed. In the paper authors used study materials from different courses, which were taken by them in the University Centre in Svalbard, University inStavanger and Gubkin Russian State University of Oil and Gas. We would alsolike to mention that authors prepared the work in close collaboration, overwhelming majority of issues was discussed and the whole paper represents aresult of a joint work and therefore most of the arguable points werehighlighted and scrutinized. The work presents mostly analytical approaches butfor some integrals calculations special numeric simulation software Maple™ wasused. This paper is the first part of Cold Climate Operations research and nextpart will be dedicated to the winterization challenges. Introduction Vessel icing is known to be a serious threat for the vessel stability andpossibility of carrying out marine operations in cold regions of high latitude(See Fig. 1). Ice accumulation can easily cause vessel destabilization andcapsizing - and there are lot of records of such accidents from the veryancient times up to the last year. On of possible reasons the Kolskaya jack-upcapsized as it is discussed now was icing on the platform together with harshenvironment conditions. With regard to the latest news from Gazprom and Shtokman Development A.G.there is a need to reconsider the development concept for the Shtokman field toimprove insufficient economy of the project. This anticipates possibility offull subsea production with no floating facilities which has shown goodperformance on the Ormen Lange, Norway. For the effect of different conceptestimations winterization concerns are also important and may put certainlimitations on the possible technical solutions. Despite of the fact that the phenomenon of vessel icing has a long recordhistory it is not well studied and even discussed. The answer to this is thefact that first knowledge of vessel icing was presented by fishermen and marineexplorers. And it is quite obvious that they didn't stay in the area where thevessel was subjected to icing - on the contrary the only rational action toescape was to leave to another location. Nowadays when world-growing demand ofhydrocarbons calls for exploration and production in severe Arctic region, theproblem of vessel icing has gotten new light. Point here is that duringexploration and all the more so production operations we merely can't leave thelocation for a very long time (depends on type of activity, for some of themtime of planned work is up to 50 years). It means that new methods of icingprevention and de-icing should be invented which is completely impossiblewithout clear understanding of mechanisms of the process.

The integrity of compressors and pumps is of paramount importance for the gas and oil industry. Failures may result in serious production losses that are in no proportion with the cost of the equipment involved. Besides, the equipment may be inaccessible for maintenance for a long period of time due to unfavourable weather conditions. The requirements of compressors with respect to pressures, capacity, power and operating range, are increasing. The answer to this is innovative compressor concepts, advanced materials and manufacturing techniques. Unexpected phenomena, however, for instance due to fluid structure interactions, will occur that can lead to serious damage of the machine. In this paper such a phenomenon is discussed by presenting a case study. On the NAM L9 platform, a centrifugal compressor was operated for the transport of gas to shore. The compressor showed serious vibrations at certain conditions that finally led to failure. An analysis of the vibration measurements showed that extremely large vibrations could occur at the blade passing frequency. By means of modeling, an analysis could be made of the acoustic resonances that could possibly occur in the compressor. It was found that a likely cause of the failure was a resonance mode in the shroud cavity of the 3rd and 4th stage. The acoustic resonance modes could be excited by pulsation sources present in the machine. Especially, the sources at the low solidity vanes were suspected to contribute to the excitation of the resonance. Vortex shedding at the impeller edge was also suspected to contribute. The resonance in the cavity may exert large dynamic forces near the trailing edge of the impeller shroud. Due to a structural vibration modes of the shroud, a fatigue failure occurred. The paper describes the root cause analysis consisting of an analysis of the acoustic and structural vibration modes. The consequences for the design of similar compressors are subsequently reviewed. A future outlook is presented concerning dense gas compression systems for CO2 and high pressure reinjection.

This paper introduces a rock typing method for application in hydrocarbon-bearing shale (specifically source rock) reservoirs using conventional well logs and core data. Source rock reservoirs are known to be highly heterogeneous and often require new or specialized petrophysical techniques for accurate reservoir evaluation. In the past, petrophysical description of source rock reservoirs with well logs has been focused to quantifying rock composition and organic-matter concentration. These solutions often require many assumptions and ad-hoc correlations where the interpretation becomes a core matching exercise. Scale effects on measurements are typically neglected in core matching. Rock typing in hydrocarbon-bearing shale provides an alternative description by segmenting the reservoir into petrophysically-similar groups with k-means cluster analysis, which can then be used for ranking and detailed analysis of depth zones favorable for production. A synthetic example illustrates the rock typing method for an idealized sequence of beds penetrated by a vertical well. Results and analysis from the synthetic example show that rock types from inverted log properties correctly identify the most organic-rich sections better than rock types detected from well logs in thin beds. Also, estimated kerogen concentration is shown to be the most reliable property in an under-determined inversion solution. Field cases in the Barnett and Haynesville shale gas plays show the importance of core data for supplementing well logs and identifying correlations for desirable reservoir properties (kerogen/TOC concentration, fluid saturations, and porosity). Qualitative rock classes are formed and verified using inverted estimates of kerogen concentration as a rock-quality metric. Inverted log properties identify 40% more of a high-kerogen rock type over well-log based rock types in the Barnett formation. A case in the Haynesville formation suggests the possibility of identifying depositional environments as a result of rock attributes that produce distinct groupings from k-means cluster analysis with well logs. Core data and inversion results indicate homogeneity in the Haynesville formation case. However, the distributions of rock types show a 50% occurrence between two rock types over 90 ft vertical-extent of reservoir. Rock types suggest vertical distributions that exhibit similar rock attributes with characteristic properties (porosity, organic concentration and maturity, and gas saturation). The interpretation method considered in this paper does not directly quantify reservoir parameters and would not serve the purpose of quantifying gas-in-place. Rock typing in hydrocarbon-bearing shale with conventional well logs forms qualitative rock classes which can be used to calculate net-to-gross, validate conventional interpretation methods, perform well-to-well correlations, and establish facies distributions for integrated reservoir modeling in hydrocarbon-bearing shale.

Abstract The Fatigue, Aerodynamics, Structures, and Turbulence (FAST) code, developed bythe National Renewable Energy Laboratory (NREL), is an aero-hydro-servo-elastictool widely used for analyzing onshore and offshore wind turbines. This paperdiscusses recent modifications made to FAST to enable the examination ofoffshore wind turbines with fixed-bottom, multi-member support structures(which are commonly used in transitional-depth waters). This paper addresses the methods used for incorporating the hydrostatic andhydrodynamic loading on multimember structures in FAST through its hydronamicloading module, HydroDyn. Modeling of the hydrodynamic loads was accomplishedthrough the incorporation of Morison and buoyancy loads on the supportstructures. Issues addressed include how to model loads at the joints ofintersecting members and on tapered and tilted members of the supportstructure. Three example structures are modeled to test and verify the solutions generatedby the modifications to HydroDyn, including a monopile, tripod, and jacketstructure. Verification is achieved through comparison of the results to acomputational fluid dynamics (CFD)-derived solution using the commercialsoftware tool STAR-CCM+. Introduction Interest is growing in offshore wind turbines. Many offshore-wind-turbinesupport structures are being developed by modifying onshore wind turbinefoundations, or oil and gas (O&G) industry structures. The offshore windturbine support structures can be classified in three categories according tothe water depth, as shown in Figure 1. In shallow water, where the water depthis less than 30 meters, monopiles and gravity bases that extend to the seafloor are used. In transitional depth, where the water depth is between 30 and60 meters, new technologies are being created or adapted from the O&Gindustry, including jacket and multi-pile structures, which also extend to thesea floor. When the water depth is greater than 60 meters, a rigid structurefixed to the sea floor is no longer economical, and floating platforms may berequired. This paper is focused on analyzing the support structures intransitional water depths.

Abstract This article presents a probabilistic methodology for estimating oil and gasreserves. This methodology takes into account the uncertainties of importantvariables present in the economic evaluation of reserves, such as oil and gasproduction, prices, and operational costs. In addition, this paper seeks tounderstand the impact of oil price changes in the behavior of costs in the longterm. It also presents a case study that will allow identifying and analyzingthe results of the implementation of the methodology. The results show theimportance of evaluating and quantifying the uncertainties in the economicevaluation of the reserves, as well as the need to consider the effect of oilprice changes in operational costs. It points out, therefore, an alternative toestimate reserves, according to a probabilistic approach, which cansignificantly impact the volume of oil and gas economically recoverable that isdisclosed by an oil company Introduction The estimate of oil and gas reserves is one of the main processes for a companythat operates in the petroleum sector. However, this process is particularlycomplex because it has a high degree of uncertainty in the estimate andprojection of variables present in the economic evaluation of production. In recent years, there has been an industry's effort to consider and quantifythe uncertainties in predicting oil and gas production. Probabilisticapproaches for assessing the economic variables within the process of reservesestimation, such as prices, investment, and operational costs are alsorecurring themes in the industry. However, the economic evaluation ofproduction and therefore the estimate of reserves, continues to be performedpredominantly by deterministic methods (Finch et al., 2002). It is also noted an industry's effort in modeling the dependence betweendifferent variables involved in reserves estimation. However, studies thatanalyze the dependence between variables in the development of models of riskanalysis occur mainly in the financial media (Accioly, 2005). Thus, thereserves evaluation still needs an improvement in the consideration of thedependence of variables involved in this process. Among the variables involved in the evaluation of reserves, the operationalcost appears as an important variable to determine the economic limit ofproduction of an oil field. Therefore, this variable is crucial in the estimateof oil and gas reserves. One of the exogenous factors that most influence the behavior of operationalcosts is the oil price (Bradley and Wood, 1993). Thus, modeling the dependencebetween price and cost is essential in the process of estimatingreserves. This paper presents an enhancement for the probabilistic evaluation of thereserves, which takes into account the dependence relation between theoperational cost and the oil price which represent key variables for thereserves estimation. Criteria and Classification for Reserves Estimation Procedures for estimating reserves are discussed for over seventy years. However, this issue remains a subject of debate and studies to date. Thisoccurs due to historical revisions in the estimated volumes, emergence of newtechnologies and regulatory laws (Harrel et al., 2005). In an attempt to unify and standardize the estimation of reserves, criteria andguidelines have been developed and disclosed to the industry for decades. Thejoint effort of some organizations resulted in the development of a singleguide with guidelines for the classification and evaluation of reserves andresources. In 2007 this guide was released and is known in the industry as theSPE/WPC/AAPG/SPEE Petroleum Resources Management System (SPE-PRMS).

Allocating production volumes across a portfolio of producing assets is a complex optimization problem. Each producing asset possesses different technical attributes (e.g. crude type), facility constraints, and costs; In addition to these field-level specifications, there are corporate objectives and constraints (e.g. contract delivery requirements). While complex, such a problem can be specified and solved using conventional deterministic optimization methods. However, there is often uncertainty in many of the inputs, and in these cases the appropriate approach is neither obvious nor straightforward. One of the major uncertainties is the commodity price assumption(s). This paper tackles this problem in three major sections: (1) We specify an integrated stochastic optimization model that solves for the optimal production allocation for a portfolio of producing assets when there is uncertainty in commodity prices, (2) We then compare the solutions that result when different price models are used, and (3) We perform a value of information analysis to estimate the value of more accurate price models. Price modeling can affect decision-making, but it is surprising to find so little research that relates the price modeling assumptions (model type and the respective parameters) to the decisions that result from their use (capital investment, production optimization, etc.). Instead, we observe countless papers advocating for more and more complex price models, and an equally large body of work where models are estimated and compared for their accuracy. No one appears to have asked the basic question, "Do any of these models provide any incremental value for decision-making?" Here, we address this question by specifying an integrated stochastic optimization model that simulates decision-maker behavior. Using this model, we compare and contrast the various production allocation decisions that result from different price models. Simple price models are investigated and compared to several currently popular advanced price models with the goal of understanding the impact of price model assumptions (both the model type and its parameters) on decision-making. The results show that the optimum production allocation is a function of the price model assumptions. However, the differences between models are minor, and thus the value of choosing the "correct" price model, or similarly of estimating a more accurate model, is small. This work falls in the emerging research area of decision-oriented assessments of information utility/value. We believe it to be the first paper of its kind on this subject in the upstream literature.

This paper involves the use of simulation models and the decline curve analysis (DCA) as a production optimization and forecasting tools. Production data from three neighboring counties (with high, medium and low cumulative gas productions) of the Eagle Ford shale, an analogue to the Shublik shale of Alaska, was analyzed using the DCA to correlate production performance with completion (horizontal leg/stages of fracture) and length of horizontal leg. We built and run generic simulation models using realistic range of properties. Simulation results provided a better understanding of interplay between static properties and dynamic behavior. The simulation results highlight how and when the key influential elements such as gas desorption, fracture closure with depletion, varying medium and fracture properties, different hydraulic fracture configuration, and various natural fracture networks will affect the well production. The use of the method proposed in this paper would result in better and more reliable production forecast at the Eagle Ford and other young producing shale reservoirs possessing short production history. The modeling of these complex reservoir geometry and fracture networks would give an extensive understanding of the flow mechanics in shale reservoirs and identify the key parameters affecting production performance. It would also serve as a screening tool for fracturing/re-fracturing operations and give optimal hydraulic fracture configuration for various mediums and natural fracture networks. Results from the decline curve analysis of 24 producing wells with production histories of 9-57 months showed an increase in reserves with more fracture stages but not at all instances which makes the use of simulation models very valuable and necessary in obtaining further results and explanations. DCA generated different forecast depending on which part of data were used. This clearly indicated the need for running simulations. Simulation runs can generate more reliable production forecast of which the decline part can be used to evaluate the capability of DCA to reproduce the production profiles. The results from simulation can provide a clear picture of the role of key influencing parameters from both reservoir and well stimulation/completion on well production performance. The results from this study will provide answer to the following questions: How long the production history needs to be for DCA to generate reliable forecasts? What are the key reservoir and completion elements that strongly affect the production? And what parameters control the choice of well spacing?

Abstract Casing has a higher likelihood of failure in compacting reservoir than in a typical reservoir. Casing fails because reservoir compaction induces compression and shear stresses onto it. The compaction occurs as reservoir pressure depletes during production. High compacted reservoirs typically are composed of unconsolidated, overpressured rocks such as chalk, diatomite, and sandstone. Pore pressure depletion increases effective stress, which is the rock matrix stress pushing upward against overburden pressure. Effective stress may exceed rock compressive strength, inducing compaction. Wells in compacting reservoirs are likely to fail and to have high deformation rates. This paper introduces the concept of structural reliability to quantify the probability of casing failure in compacting reservoirs. Probabilistic models for casing capacities are developed using current design methods and a reservoir compaction load observed using finite-element model simulations. The proposed probabilistic models are used to define two limit-states functions used in predicting the probability of casing failure for two possible modes of failure: axial yielding and buckling failures. A limit-state function describes the casing condition as the casing experiences a reservoir compaction load. The limit state function is the input in component and system analyses for estimating the probabilities of failure as reservoir pressure is depleting. Sensitivity and importance analyses are also performed to determine the role and significant of parameters and random variables affecting the casing reliability. Applying the knowledge produced from this research to casing design can improve design reliabilities and forecast the probability of casing failure in compacting reservoirs. Introduction Casing failure and deformation are becoming problems in mature oilfields. The number of these oilfields has been increasing since 1980, where failures are a major problem to cause wells to stop producing or preventing necessary well services. The number of failure reported from Shengli oilfield, Ekofisk chalk field, and Belridge diatomite field combined to over 10,000 casing failures (Yodavich et al. 1998, Fredich et al. 1998). A major cause of casing failure in these mature fields is reservoir compaction. Reservoir compaction causes casing to experience large additional stresses that casing may not be designed for. Assessing and predicting casing conditions in mature fields where reservoirs tend to compact are important in order to prevent casing failures. Many papers have shown casing failure mechanisms and reservoir compaction mechanisms using methods such as geomechanical simulation, analytical formulation, and probabilistic modeling. Geomechanical simulations are widely used to determine high stress zones in the formation around the field. Earlier geomechanical models depend on 2D modeling to find crucial depths and compaction rates related to the amount of production (Chia et al. 1989, Fredich et al. 1998, Hansen et al.1995, Wooley et al. 1988). Today technology and software allows users to create 3D reservoir models or use an existing model from reservoir simulation to compute compaction rates and stresses in the formation (Bruno 2001, Hilbert et al. 1998). Modeling provides answers to casing failure mechanism as reservoirs compact and high compaction location. Although these models prove to be very useful, they cannot account for uncertainties from model parameters or methods used in simulation. Also, modeling results do not quantify the accuracy and correctness of its results. Geomechanical simulations also take time to build and run.

Abstract This paper presents a sand production model that predicts the stability of wellbores and perforation tunnels, as well as the mass of sand produced. Past analytical, numerical, and empirical models on material failure and erosion mechanisms were analyzed. The sand production model incorporates shear and tensile failure mechanisms. A criterion for sand erosion in failed sand was proposed based on a force-balance calculation on the sand face. It is shown that failure, post-failure sand mechanics, and flow-dominated erosion mechanisms are important in the sand production process. The model has a small number of required input parameters that can be directly measured in the laboratory and does not require the use of empirical correlations for determining sand erosion. The model was implemented in a numerical simulator. Experiments using different materials were simulated, and the results were compared to test the model. The model-generated results successfully matched the sand production profiles in experiments. When the post-failure behavior of materials was well-known, the match between the simulation and experiment was excellent. Sensitivity studies on the effect of mechanical stresses, flow rates, cohesion, and permeability showed qualitative agreement with experimental observations. In addition, the effect of two-phase flow was presented to emphasize the importance of the water-weakening of the sand. These results showed that catastrophic sand production occurs following water breakthrough. Introduction A conventional and conservative approach to completing a sand-prone well is to install a mechanical means of sand control, such as gravel packs, fracpacks, and screens. In some cases, sand management is practiced through oriented perforating and rate control. An openhole completion can be an alternative to a cased and perforated completion to reduce the near-perforation fluid velocity. Before deciding on how to prevent or minimize sanding, the benefits and disadvantages of sand control/management must be evaluated carefully, and the assessment of qualitative and quantitative sanding risk is crucial. Many publications present sand failure and sand production models supported by experimental results (Hall and Harrisberger 1970). Some models deal with the problem of sand stability and failure (Bratli 1981; Risnes 1982). With the advent of numerical simulations, such as finite element modeling (FEM), sand production became a popular numerically simulated problem because of its complexity. However, most of these models rely on parameters that may or may not be experimentally measureable. In many instances, the physical significance of some of these parameters is not obvious. While most of the research work has generated relevant insights on sand production, a comprehensive model that can adapt to different experimental settings and to the field is not available because of one of two reasons: (1) a lack of model sophistication or (2) overly complicated models with excessive input requirements. This calls for a flexible and complete model with a quick runtime and a small and measureable set of parameters that provides reasonably accurate results. The purpose of this paper is to showcase a general 3D numerical model that describes the process of sand failure, erosion, and production quantitatively(Fig. 1).The sand production model incorporates two sequential phenomena. The first one is the failure of the near-wellbore region (wellbore or perforation), which is a necessary condition for any sand production. The subsequent step for sand production is "erosion." This process refers to the removal of the sand from the failed region. In the model, a force balance is conducted between the frictional forces mechanically holding the sand in the formation and the hydrodynamic force (exerted by the flow) that induces detachment of the disaggregated sand. Gridblocks for which the frictional force is overcome by the hydrodynamic force are removed from the simulation and are assumed to be produced into the well. The model is verifiable with distinct sets of experiments, which then could extend and offer a reasonable prediction tool for sand-production characteristics for field cases. The numerical model also obtains results that are beyond the reach of simpler analytical solutions.

This paper describes the background, test methodology, experiment program and analytical methods used for a project to predict the peak mooring system loads that occur when a floating offshore structure encounters a first year ice ridge. The project included the construction of simplified physical models of a Spar at 1/30 scale and a Floating Production Unit (FPU) at 1/40 scale. The Spar was a representative structure with a downward breaking cone and a vertical neck designed for operation in ice. A partial spar, consisting of the cone only was also evaluated. The Floating Production Unit (FPU) was a simplified barge. This model was tested with a rigid connection to the towing carriage and also on a representative mooring system that allowed for some compliance. The model FPU was also fitted with two load measuring panels designed to measure local ice loads on the hull. The methods of producing the model ridges and measuring their physical properties are described. Each model was tested in a range of ridge geometries from temperate to Arctic regions. The experiments were carried out in the ice tank of the National Research Council of Canada's Institute for Ocean Technology. This paper describes the first phase of experiments on the spar model completed in December 2009 and the first phase of experiments on the FPU completed in June 2010. The paper also presents the description of a parallel numerical approach to the problem, which looks at the methods needed to model the ridge-structure interaction using finite element methods. The results of the simulations and experiments are discussed in general terms. Copyright 2011, Offshore Technology Conference., Arctic Technology Conference 2011, 7 February 2011 through 9 February 2011, Houston, TX

With the growing interest in low-permeability gas plays, foam fracturing fluids are now well established as a viable alternative to traditional fracturing fluids. Present practices in energized fracturing treatments remain nonetheless rudimentary in comparison to other fracturing fluid technologies because of our limited understanding of multi-phase fluid- loss and phase behavior that occurs in these complex fluids. This paper assesses the fluid-loss benefits introduced by energizing the fracturing fluid to estimate when and why energized fluids may be suitable. A new laboratory setup has been specifically designed and built for measuring the leak-off rates for both gas and liquid phases under dynamic fluid-loss conditions. This paper provides experimental leak-off results for linear guar gels and for N2- guar foam-based fracturing fluids under a wide range of fracturing conditions. In particular, the effects of the pressure drop, the rock permeability, the fluid shear rate, the polymer concentration, and the foam quality are investigated. Analysis of dynamic leak-off results provide an understanding of the complex mechanisms of viscous invasion and filter-cake formation occurring at the pore-scale. This study presents data supporting the superior fluid-loss behavior of foams, which exhibit minor liquid invasion and limited damage. It also shows direct measurements of the ability of the gas component to leak-off into the invaded zone, thereby increasing the gas saturation around the fracture and enhancing the gas productivity during flowback. The conclusions not only confirm but add to the findings of McGowen & Vitthal (1996) for linear gels and the findings of Harris (1985) for nitrogen foams.

Accurate simulation of chemical flooding requires a detailed understanding of numerous complex mechanisms and model parameters where grid size has a substantial impact upon results. In this paper we show the effect of grid size on parameters such as phase behavior, interfacial tension, surfactant dilution and salinity gradient for chemical flooding of a very heterogeneous oil reservoir. The effective propagation of the surfactant slug in the reservoir is of paramount importance and the salinity gradient is a key factor in ensuring the process effectiveness. The larger the gridblock size, the greater the surfactant dilution, which in turn erroneously reduces the effectiveness of the process indicated with low simulated oil recoveries. We show that the salinity gradient is not adequately captured by coarse grid simulations of heterogeneous reservoirs and this leads to performance predictions with lower recovery compared to fine grid simulations. Due to the highly coupled, nonlinear interactions of the many chemical and physical processes involved in chemical flooding, it is better to use fine-grid simulations rather than coarse grids with upscaled physical properties whenever feasible. However, the upscaling methodology for chemical flooding presented in this paper accounts approximately for some of the more important effects, as demonstrated by comparison of fine grid and coarse grid results and is very different than the way other enhanced oil recovery methods are upscaled. This is a step towards making better performance predictions of chemical flooding for large field projects where it is not currently feasible to perform the large number of simulations required to properly consider different designs, optimization, risk and uncertainty using fine-grid simulations.

Laboratory experiments are an excellent way to visualize and improve our understanding of the hydraulic fracturing process. However, in order to truly apply the results of laboratory work to the field, an understanding of what artificial conditions are being created during the laboratory process must also be developed. This paper describes 3D finite element modeling and associated results using actual laboratory block tests as a basis. These models consisted of seven basic block systems, including a single layer system, with and without a wellbore, as a control case; a three-layer model with and without a wellbore; and a seven layer system, with a wellbore, without a wellbore, and with a cased wellbore. These seven systems were based on actual triaxial hydraulic fracturing experiments that were performed on mid-sized blocks (11 × 11 × 15 in) consisting of the same single, three, and seven-layers. The fracture growth patterns in the actual laboratory tests were extremely complex, not at all like the planar fractures dictated by hydraulic fracturing theory. The intent of the modeling was to 1) determine the spatial stress contrasts being created by the material property contrasts of the layered systems in the triaxial system and 2) determine if the complex fracture growth could be accounted for by these modeled contrasts. Results were also used to determine the potential for shearing across the layered systems. A commercial, modeling software, capable of numerically determining the 3D stress distributions in the various porous media, was used. Numerical results were validated with analytical calculations. The results of the modeling provide insight into the time-dependent application of stresses in a laboratory setting. It helped to explain the complex fracture growth in the actual experiments and gave some insight into the conditions that would cause vertical or horizontal fracture growth in a layered system of different material properties. The modeling also documented the creation of shear stresses which accounted for some fracture path deviation. The results of this paper aid in understanding the mechanisms of complex hydraulic fracture growth in reservoirs settings. Additionally, insight into the shear and tensile fracture mechanisms that generate acoustic events was gained.

Abstract The Late Jurassic Arab Formation consists of complex carbonate and evaporite facies associations deposited along ramps and intra-shelf Arabian basins, which form large hydrocarbon fields. Most of the time, the 3D reservoir characterization of such reservoirs is challenging, due to superimposed diagenetic overprints. The aim of this paper is to present an integrated approach using original rock-typing and modeling methods for the characterization of the four main reservoirs of the Arab Formation in Maydan Mahzam Field (Qatar). A sedimentological study was conducted on cores, and a sequence stratigraphy framework was developed. Three depositional models are proposed to illustrate the progradation of the Arab D carbonate platform toward the Southeast and the deposition of inner ramp/sabkha facies of the Arab A, Arab B and Arab C reservoirs. Rock-types that are characterized by specific geological, petrophysical and Kr/Pc properties have been defined from cores and thin sections, taking into account log response and SCAL measurements. These rock-types have been extended to all the wells by mean of a semi-interactive statistical classification applied on log data. They have been propagated in a 3D grid using a non-stationary geostatistical approach guided by 3D probability cubes. The probability cubes calculation is based on local vertical proportion curves determined from well sets and from the sedimentological models which cover undrilled areas. This paper contributes to a better understanding of the sedimentology of the Arab Formation in Qatar and helps to refine the regional distribution of the Arab D reservoir facies. It demonstrates that an accurate rock-typing scheme combined with the definition of a sequence stratigraphy framework are of prime importance for building 3D static models, which honor geological concepts for carbonate reservoir simulation.

This reference is for an abstract only. A full paper was not submitted for this conference. Abstract One of the main difficulties for modeling and producing carbonate rock oil reservoir in the Middle East is linked to the fact that these reservoirs often display numerous and variable heterogeneities, ranging from plug micro-scale heterogeneity (texture, pore types, cementation, …) to field mega-scale heterogeneity (geometries and facies, fracturation and faulting). Because these heterogeneities often result in significant variations in permeability and saturation, and hence in productivity it is absolutely necessary to capture all of these scales of heterogeneities and understand their origin. Various factors can be implied alone or combined between them: depositional environment, sequence stratigraphy, early or late diagenetic overprint and fracturation scheme. The aim of this paper is to present an integrated approach used to characterize very heterogeneous reservoirs and in particular those presenting highly permeable levels. Some comparative studies using different approaches have been carried out simultaneously in order to provide key information on origin and geometry of these highly heterogeneous carbonate reservoirs. The first approach is based on outcrop analogs. In order to provide 2D/3D characterization of the main depositional bodies some outcrop analog studies have been carried out. The main objectives of this approach were to understand the sedimentary architecture and distribution of the reservoir facies related with sedimentology, diagenesis and sequence stratigraphy. The lateral continuity of sedimentary bodies and particularly of highly permeable levels is one of the most important parameter to take into account during the modelling process. Diagenesis effects and modeling must also be closely considered in order to be able to address its relationship with sequence stratigraphy, and its impact on the reservoir characteristics. In some cases, there is a strong relationship between vertical facies heterogeneity and sea level change. Reservoir drains may result from confined deposition or early dissolutions caused by meteoric or mixed waters linked with exposure surfaces. In these cases, heterogeneity is mainly due to early diagenesis. Corresponding facies and associated petrophysical characteristics have to be properly described on outcrop. However early diagenesis has to be distinguish from late diagenesis. Some high permeability levels are often associated with late dolomite type such as saddle dolomite. These facies, resulting from hydrothermal water circulation are systematically associated with fault and fractures network. In this case, analog studies allowed a better understanding of the geometrical relationships between facies, of the diagenetic effects with respect to the distance from fault, and of the fracturation associated network. All these are key information to better assess the variographic parameters into the reservoir models. So, outcrop analog approach provides information about: sedimentary architecture, size of sedimentary bodies and quantitative information about primary and secondary diagenesis effect such as diagenesis parameters distribution, facies envelop size and diagenesis timing. These three kinds of information are necessary to build and populate an accurate geological model. The second approach is based on subsurface studies. Cores have to be described in detail in order to determine sedimentological facies families having homogeneous lithology and representing specific depositional environment. Cement types and porous network, mainly linked to diagenesis have also to be described precisely from thin sections. However, none of such detailed studies is useful without confronting the so-defined sedimentological facies of a reservoir with their corresponding petrophysical and wireline log properties. For each sedimentological facies, the associated diagenetic overprint has to be analysed in order to define the relationships between facies and diagenesis, the impact of their stratigraphic position on their behaviour, and their relations with petrophysical and wireline log properties. The challenge will consist in integrating many sources of data from cores, thin sections, plug (CCAL & SCAL), wireline logs and reservoir engineering data (well tests, production logs…) in order to derive pertinent Petro Diagenetic Groups. A good correlation between the defined Petro Diagenetic Groups and wireline logs will permit to use Petro Diagenetic Groups as learning set in a statistic multi well analysis to define Electrofacies that will be extrapolated to the whole set of non-cored and/or undescribed wells. Of course, an accurate log data screening and if necessary processing (decompaction, normalisation, HC corrections, shoulder bed effects and thin beds lower than log resolution removal) is mandatory for good results. A blind test is necessary at this stage to control the quality of the generated Electrofacies. At least this approach based on subsurface studies will produce Electrofacies along all cored and uncored wells. The resulting Electrofacies are well defined in terms of sedimentology and depositional environment, diagenesis (pore and cement types) and petrophysics. Consequently, because they keep a geological consistency and because they are well defined in terms of petrophysics, they can be used as the building blocks of the geological and reservoir models. In conclusion, the confrontation of the conceptual sedimentological and diagenetic models coming from outcrop studies giving information such as size and geometries of sedimentary bodies and results coming from subsurface studies will help to define variographic parameters and trend maps to be used to constraint the 3D geological model. Electrofacies have to be propagated in the reservoir through depositional and diagenetic conceptual models, and being petrophysically meaningful (consistent in conventional cores and log domains). If possible, these results have to be confronted with 2D or 3D seismic to constrain the distribution of reservoir facies between wells, inter wells connectivities and faults dynamic impact. This integrated approach promotes discussion and exchange between geologists, geophysicists, petrophysicists and reservoir engineers, essential to optimise reservoir modelling of heterogeneous carbonate reservoirs.

One of the petroleum industry's goals is to reduce the environmental impact of oil and gas operations in environmentally sensitive areas. To achieve this, a number of Environmentally Friendly Drilling (EFD) technologies have been developed to varying degrees but few have been integrated into a field demonstrable drilling system (i.e., combination of technologies) compatible with ecologically sensitive or off-limits areas. The main purpose of this paper is to present a decision-analytic technology selection process. The proposed method is based on a systems analysis that can be used for integrating current and new EFD technologies into an optimal EFD system. The system draws upon a large number of technologies (more than 100) identified by a government-industry joint venture studying low impact operations in sensitive ecological areas. In order to provide flexibility to the user, a small number of systems (1~5) are proposed for a given site, instead of a single best system. An optimization scheme is suggested based on a combination of multi-attribute utility theory and exhaustively enumerating all possible technology combinations to provide a quantitative rationale and suggest the best set of systems according to a set of criteria, with the relative importance of the different criteria defined by the decision-maker. This methodology is designed to help decision-makers select an optimal drilling system for a given site in order to minimize environmental impact and maximize profit at that specific site. An application of the proposed approach is described by conducting a case study in Green Lake at McFaddin, TX; some of the difficulties in using this approach in practice are also discussed. This paper describes the results of the case study which provided a more logical and comprehensive approach that maximized the economic and environmental goals of both the landowner and the oil company leaseholder.

The challenges associated with the construction of an injection well for carbon sequestration are cross disciplinary, but highly manageable. Site selection, reservoir identification and formation evaluation involve geological and reservoir specialists that perform detailed evaluations of the subterranean environment.[1-4] Materials selection identifies components that are designed to withstand the unique chemical and physical environments of these wells. Sealant selection is key to providing long term integrity of any well, with Portland cement being the material of choice for most oil field applications. Work on Carbon Sequestration in subterranean formations has renewed interest in investigating the long term effects of CO2 on Portland cements. Portland cement will react with the injected CO2, and while recent research indicates these conventional cements are not a concern, additional work is ongoing to improve the long term effectiveness of the wellbore sealant. Efforts have focused on enhancing the properties of Portland cement by reducing the permeability of the set cement, lowering the concentration of materials in the cement that react with CO2, or replacing the conventional Portland with specialty cements. Complementing technologies that have been used to further promote long term seals include the use of in-situ swell packers, and self healing cements. Additional work has been done in evaluation of the long term stress environment of the well. This work goes beyond the simple drilling and completion of the well to include input from long range reservoir and wellbore stress modeling through the full life cycle of the well. These stresses are evaluated to confirm the selected sealants can withstand the changing stress environment. This paper discusses various identified solutions to the challenges of selecting a proper wellbore sealant for a CO2 injection well. Additionally, the paper reviews the available sealant technologies, their application, and includes a discussion of stress modeling for these wells.

This paper describes updated uncertainties for use with predicted geomagnetic parameters within magnetic Measurement-While-Drilling (MWD) survey tool error models. These models are used to define positional error ellipsoids along the wellbore which assist in hitting geological targets and missing existing wellbores. The declination, dip angle and total field strength of the Earth's magnetic field are used with magnetic survey tools for surveying the wellbore. These values are often obtained from mathematical models such as the British Geological Survey Global Geomagnetic Model (BGGM). As the Earth's magnetic field is continually varying with time the BGGM is updated annually to maintain accuracy. However a global predictive model cannot capture all sources of the Earth's magnetic field which results in uncertainties of the predicted parameters. The Industry Steering Committee on Wellbore Surveying Accuracy (ISCWSA) published a MWD error model in 2000 (Williamson, 2000). The geomagnetic field uncertainties that are part of this model were derived from work done by the BGS in the early 1990s. Since then more accurate data from magnetic survey satellites have been introduced into the BGGM and the uncertainty of the predicted geomagnetic field parameters has been reduced. The original approach to deriving the uncertainties involved separating the various error sources in the magnetic field and assessing them individually. This paper uses a simpler approach where clean orientated magnetic down-hole data are simulated using geomagnetic observatory data. Spot absolute measurements of the magnetic field made at observatories around the world are adjusted for the crustal magnetic field to make them more representative of hydrocarbon geology. The adjusted observatory data are then compared with the predicted values from the BGGM to assess the uncertainty. The uncertainties do not fit a ‘normal’ distribution so they are expressed as limits for various confidence levels. They vary with time and with location and, in their derivation, do not assume any underlying empirical error distribution. Options to further reduce the uncertainties using data from local magnetic surveys (In-Field Referencing) and observatories (Interpolation In-Field Referencing) are also described. The use of the revised geomagnetic uncertainty values in the MWD error model will reduce wellbore position uncertainty to reflect the increased accuracy from recent improvements in geomagnetic modelling.

This reference is for an abstract only. A full paper was not submitted for this conference. Abstract Description This paper describes the project management processes used to design and procure the topsides facilities for the Gumusut-Kakap project. Gumusut-Kakap is a "mega-project" to be installed in Malaysian deepwater to produce up to 150,000 bpd sales quality oil whilst injecting up to 220,000 bpd seawater and up to 300 MMscfd gas to the reservoir. The topsides facilities are thus world-class in scale. They will be supported on a new-build, moored semi-submersible, receiving production from subsea wells. Interfaces between the topsides and the hull, the subsea systems and the export pipeline are complex and are described in the paper. The topsides execution strategy is aligned to the project's drivers: Safety, Technical Integrity, Capability Development, Schedule and Cost. These drivers were enforced throughout the FEED phase which was executed in Shell's US design centre and the Detailed Design phase which was transitioned to a Malaysian EPC contractor to facilitate Capability Development, Schedule and Cost. The challenges, plans and learnings from this transition are described in the paper. The project management processes developed in Shell's deepwater projects group were adapted for the Gumusut-Kakap project and used to support the EPC contractor. Key processes implemented include: Design Verification, Weight Management, Interface Management and Flawless Start-Up, enabled through key Information Technology (IT) tools. These processes and their customisation are described in this paper. The results presented in the paper will be applicable to mega-projects, especially those in areas developing local capabilities. The conclusions are:Alignment of stakeholders on the project drivers is vitalContractor capability is a key areas to address in transition planning and capability developmentProject management processes need to be customised for the particular project The technical contribution of this paper is through:Base plan for transitioning a design from a company center to the host countryImproved techniques for developing capability of key contractorsEnhanced tools for managing complex project interfaces Acknowledgement The authors would like to thank the management of Sabah Shell Petroleum Company and their Gumusut-Kakap joint-venturers: Petronas-Carigali, Conoco-Phillips and Murphy Oil for their permission to publish this abstract.

This reference is for an abstract only. A full paper was not submitted for this conference. Abstract Description: Managing the safety of very large construction workforces (over 25,000) made up of workers from very diverse backgrounds and experience levels can be a major undertaking on any project. The Qatargas 2 Onshore Project experience involved building two mega LNG trains, each capable of producing 7.8 million tons of LNG per annum, and associated storage and export facilities in Ras Laffan Industrial City in the State of Qatar. At peak activity levels, the workforce exceeded 28,000 workers originating from more than 30 countries, with a majority having relatively low experience levels. Managing the safety of this workforce involved craft and safety training, proper personnel protective equipment, managed work schedules, multilingual communication programs, acclimitization and special programs to combat the harsh Middle East summers, and a comprehensive set of structured safety programs designed to be effective for a large number of workers. Underpinning all these was an uncompromising management commitment to safety characterized by the project goal "Nobody Gets Hurt." The first priority was to provide basic safety training and instill personal safety awareness and a strong safety culture in the workforce. This was especially important and challenging considering many of the workers came from non-industrial backgrounds. Also critical at a very early stage was proactively addressing the numerous worker health and welfare needs created by a diverse workforce of this size. With a relatively short project duration, it was imperative to reduce the chances of having worker injuries as quickly as possible. To achieve this goal, comprehensive, tailored training programs were required, as well as safety programs which were designed with two things in mind - 1) to allow individual supervisors and workers to more easily understand and relate to their job and related safety requirements, and, 2) to enable effective implementation of these programs, involving many workers across a large, high-activity site (at peak activity, there were more than 300 cranes on site). The QG2 Project has expended more than 250 million work hours to date and achieved safety levels of 0.02 Lost Time Injuries/200,000 work-hours. Management leadership and commitment at all levels of the organization in strong partnership with the Contrator leadership was instrumental in overcoming numerous challenges and achieving this safety performance. This paper will discuss the challenges faced and the key safety programs employed including Competency and Training, Heat Stress Prevention, Leading Indicators and Worker Welfare Programs. Application: Recommendations, lessons learned, and future opportunities for effective management of safety on future large-scale projects of a similar nature. Results and Conclusions: The key success factors for effective safety management of these types of large, onshore construction workforces include strong and visible management commitment and safety leadership between owner and contractors, continuous safety program 2 IPTC 12446 innovation and enhancement, a vigorous company/contractor partnership, structured programs targeting the essential elements of safety, concern for worker welfare, use of recognition programs, and commitment to learning from both internal and external project safety experiences. Technical Contributions Not applicable.

Formate-based mud has been used to drill deep gas wells in Saudi Arabia since 2004. This mud typically contains XC-polymer, starch, polyanionic cellulose, and a relatively small amount of calcium carbonate particles. This mud (typically 90 pcf, pH of 10) is used to drill a deep sandstone reservoir (310°F). Various cleaning fluids were proposed to remove drilling mud filter cake; including: solids-free formate brine, formate brine doped with organic acids (acetic, formic, citric, and lactic acids), and enzymes. The main objective of this paper is to assess the effectiveness of these cleaning fluids in removing formate drilling mud filter cake. A dynamic HPHT cell was first used to determine characteristics of the formate mud filter cake. Drilling mud and completion fluids were obtained from the field. The experiments were conducted using ceramic disks at bottom hole conditions. Compatibility tests between formate brine and cleaning fluids were performed at 300°F and 500 psi using HPHT visual cells (see-through cells). Circulation of solids-free formate brine did not remove the external filter cake. Citric acid at 10 wt%, formic acid, and lactic acid were found to be incompatible with formate brine at room temperature. However, these acids were compatible with formate brine at temperatures greater than 122°F. Mixing of these acids with the formate in the field may cause operational problems. Only acetic acid and enzymes were compatible with formate brine. A formula was developed that is compatible at room and reservoir temperature. This formula was effective in removing filter cake. A corrosion inhibitor was added to protect downhole tubulars. This paper will discuss the development of this formula and all tests that led to its development.

This reference is for an abstract only. A full paper was not submitted for this conference. Gas hydrates, also known as clathrates are naturally occurring icelike solids in which guest molecules like methane, chlorine, carbon dioxide, nitrogen etc. are entrapped inside host (Water) molecule. It is estimated that 1 m3 of natural gas hydrate can accommodate around 164.3 m3 of methane gas. Volume of carbon contained in methane hydrates worldwide is estimated to be twice the amount contained in all fossil fuels on earth including coal. Also combustion of methane adds significantly less carbon dioxide to the atmosphere than combustion of either coal or oil. The NGHP is being monitored by a Steering Committee headed by Secretary, MOP & NG with Oil Industry Development Board (OIDB), ONGC, GAIL etc. as members. The D.G. of Hydrocarbons has drawn up an ambitious plan and prepared Road Map to tap these gas hydrate resources. Minister of Petroleum & Natural Gas, Government of India flagged off the drill ship on April 30 from Mumbai for undertaking drilling, coring and logging activities. The importance of gas hydrates as future source of natural gas is very evident from the above mentioned details and a lot of research work on the techno-commercial aspects of gas hydrates is still in progress across the world. In this paper focus is on the various exploration and exploitation techniques of gas hydrates and its related environmental hazards. Factors affecting the formation of gas hydrates, origin of In-situ gas hydrates and Hydrates stability zones (HSZ) will be discussed. Properties of gas hydrates like acoustic permittivity and various exploration techniques used for the identification of gas hydrates will be analyzed. Application of high frequency electromagnetic field & Gas lifting technique will be discussed and their relative merits and demerits of these techniques will be compared with the help of a case study.

A number of tests were performed in Yamburggasdobycha Gazprom's fields in Northern Siberia area to evaluate the performance of multiphase flowmeters in gas-condensate reservoir applications. The remoteness of the operation and the roughness of winter weather conditions combined with the complexity of the fluid compositions create unique challenges to the successful acquisition of well test data. The paper discusses the challenges and potential benefits of deployment in line multiphase flowmeters in the difficult operating environment of Northern Siberia. The reduced logistics and the ability to monitor in real time the true evolution of the gas and condensate wells provide an in-depth view of the actual well performance. The evolution of the real dynamics of the wells stabilization after a change of choke can be observed and monitored accurately with the in-line Venturi – Dual Energy gamma ray multiphase flowmeter. The importance of the hydrate detection and mitigation processes is essential in the performance of successful tests in the Siberian gas well environment. The paper details the methodology of the comparison of the well test rates of gas and condensate against traditional means of measurement presently deployed in Siberia. It is based on a rigorous mass balance approach, which enables to consider properly the mass transfer effects when comparing flowrates at different measurements conditions of pressure and temperature. The presence of hydrates despite the extremely low water content of the effluent is detected by the multiphase flowmeter, which therefore provides also confirmation of the hydrate build up curve. The challenges to collect representative samples of condensate and gas to ensure proper set-up of the multiphase flowmeter and thus the correct computation of gas and condensate rates are presented, and a number of solutions are described. A discussion of the validity of samples for full reservoir fluid characterization provides insights on the benefits and limitation of sampling in multiphase flow combined with proper conditioning of the samples. The paper further elaborates on the comparison of the fluid composition between traditional surface sampling methods and multiphase testing methods. The utilization of the dynamic information obtained from the multiphase flowmeter to complement the understanding of the reservoir performance is discussed.

Horizontal well technology has been widely used in developing gas fields. Very commonly, these wells are hydraulically fractured to improve productivity in low permeability reservoirs. A previously developed method, the Distributed Volumetric Source method (DVS), was applied to horizontal gas wells with or without fractures to predict well performance. The method is flexible and can be easily applied. The method provides an effective tool to evaluate horizontal well design and well stimulation design for gas wells. In this paper, we conducted a well performance study by applying the DVS method to typical gas formations in East Texas Basin, San Juan Basin, and Appalachian Basin.. The objective is to determine the best practice to produce from horizontal gas wells. With the transient flow feature of the DVS method, well placement for multiple horizontal wells in a defined drainage area can be studied, and the limit of well spacing and wellbore length is identified. For fractured wells, well performance of a single fracture and multiple fractures are compared, and the effect of the number of fractures on productivity of the well is presented. Realizing that reservoir permeability and anisotropy ratio are the critical parameters in developing low-permeability gas fields, the effect of permeability on well performance, well placement and fracture treatment design is addressed in the paper.

Abstract The electrical systems needed for offshore wind farms to collect power from wind turbines-and transmit it to shore- will be a significant cost element of these systems. This paper describes the development of a simplified model of the cost and performance of such systems. The performance prediction accounts for losses as a function of the power produced in the wind farm and the length and size of the cables. The cost prediction is flexibly formulated so wind farm configurations can be evaluated by parameters such as the number of wind turbines, wind turbine size, turbine array configuration and spacing, and distance from shore. The collection system-the medium-voltage electrical grid within the wind farm, and the transmission system-the high-voltage electrical connection to an on-shore transmission line-are treated independently in the model. Data sources for the model and limitations of the data are discussed, and comparison is made to costs reported by others. The choice of transmission system technology is also addressed. This electrical system model is intended for integration into a more comprehensive model of offshore wind farm design, cost, and performance that will be used for parametric studies and optimization of wind farm configurations. Because some concepts for future offshore wind installations in deep water use floating platforms, this paper briefly discusses the application of submarine cable technology to nonfixed termination points, a departure from current practice. Introduction The National Wind Technology Center (NWTC) of the National Renewable Energy Laboratory (NREL) in Golden, Colorado, has undertaken a series of concept studies to evaluate the cost and performance of offshore wind farms. The product of these studies will be a comprehensive model of offshore wind farm design, cost, and performance suitable for parametric studies and optimization of wind farmconfigurations. The overall goal of this effort is to helpidentify technology pathways for offshore wind energy development and deployment in the United States. Offshore wind farms present an attractive option because they allow for larger wind turbines that operate in higher wind resources than land-based [1,2]. Offshore installations are also more expensive, so an understanding of their performance, cost, and optimal configurations is needed. This paper is an overview of one of these concept studies. It focuses on the power losses in wind farm electrical power collection and transmission systems, as well as the costs of the system components and their installation. A hypothetical system was based loosely on the Horns Rev offshore wind farm in Denmark. Inquiries were made with manufacturers about electrical and cost data on the required components, which were then compiled in a spreadsheet model. The performance prediction accounts for losses as a function of power output of the wind farm and length and size of the cables. The cost prediction is flexibly formulated so wind farm configurations can be evaluated by parameters such as the number of wind turbines, wind turbine size, turbine array configuration and spacing, and distance from shore.

Many predictive methods based on numerical simulation generate undesired changes on the distribution of their parameters that depend mainly on the numerical method or the grid orientation (artifacts). On the other hand, it is common to find an appropriate match of the production history through the use of reservoir properties as calibration parameters, even when this procedure generates in many cases geological inconsistencies. Also, as real time data acquisition is becoming a powerful and popular technique, it is important to achieve a methodology that allows the input of new sources of information without disturbing the history matching previously validated. In this paper a new methodology to integrate a history-matched reservoir model with other geological data is presented. It is based on the methodology proposed by Sahni and Horne1, that based on the Haar wavelet transform allows for the improvement of the history-matched geological model through the inclusion of additional geological constraints without needing to perform the history matching every time the reservoir model is updated. The first step of the method presented in this study is to match the production history of the reservoir that will be modeled by means of numerical simulation. Then, the wavelet function that better fits the distribution of the considered properties, keeping the highest Energy Compaction Ratio (ECR), is chosen. After performing the wavelet transform, the most sensitive coefficients to the production data are determined. Those that are not significant for the model validation can be modified and geostatistical interpolation algorithms can be applied (e.g. Sequential Gaussian Simulation). Finally, when the inverse transform is performed, the data set is not only validated by the production history but also by the geological properties. If the wavelet transform is not Haar, an additional benefit is obtained. It is possible to interpolate the geological information in the different regions where the data acquisition is difficult or doubtful. This new heuristic methodology has been tested in different reservoir configurations. In this paper, we validate the results achieved for a test case reservoir with patterns of 4 producers and 2 injectors. This procedure is very helpful in numerical simulation of reservoirs and it has a direct impact on its management, risk analysis and the development of depletion plans.

Managing Sustainable Annulus Pressures (SAP) is one of major well's integrity challenges in the oil & gas industry as they pose an HSE concern. As the wells ages, more wells do exhibit SAP of a varying degrees, some could be managed, and others should be dealt with on fast track basis & send to work over (if required). The objective of this paper is to provide an overview of ADCO's initiatives in managing casing sustainable annuli pressure in ADCO field. Since the introduction of ADCO SAP guidelines in June 2002, to manage casing annuli pressures and ensure the integrity of all wells during their life cycle, ADCO field embarked on an aggressive campaign to implement the guidelines and manage SAP wells effectively. The paper sheds light on how the SAP wells are being managed, base line data collection, integration with PIES (Production Injection Export System), SAP current status (compared with that recorded in early 2003) and associated KPI's. And finally touch on recommendations & way forward based on ADCO massive experience gained during the last 3 years to ensure the integrity of all ADCO wells.

Productivity index calculation has been an established tool for formulating inflow performance relationship in petroleum production engineering field. The accuracy in its prediction is highly desirable to petroleum industry to predict the well production efficiency and aid in economic analysis of the well. Inability to accurately model and predict flowing bottom-hole pressure in a well may result in erotic value of productivity index of a well. This paper present an improved model for estimating flowing bottom-hole pressure and analyse its effect on productivity index value of a vertical well without ignoring any pressure resisting terms in the governing thermodynamic equation. Satisfactory pressure differential and productivity index results were obtained at any location in the wellbore, at all time and at both steady and unsteady state period using the newly developed model. Generally the flow phenomenon after shut in requires sufficient time to stabilise or advance to pseudo steady or steady state condition has been demonstrated by this study compared with the existing models that stabilised throughout the flowing period. This study also proves that inaccuracy in the results of existing models were not only caused by the effect of pressure restriction due to friction as opined by Guo et al but may have due to oversight of all pressure restriction term in the fundamental governing equation of flowing fluid in a vertical wellbore.

This reference is for an abstract only. A full paper was not submitted for this conference. Abstract PETRONAS has been actively acquiring large volumes of seismic data in varied and difficult terrain to support its worldwide exploration, development and production activities. In the Malay Basin of Malaysia, the challenge begins with imaging complex stratigraphic reservoirs that are often below conventional seismic resolution. The Malay Basin being a fairly matured exploration & production province also poses another challenge, i.e. acquiring high quality seismic data around platforms and other obstructions. In Vietnam, our team was tasked with imaging complex fractured basement reservoirs under an overburden of clastic and volcanic rocks while in Indonesia, obtaining high quality, contiguous data over a land-marine interface required four different acquisition techniques and special processing workflows. In offshore Mozambique, East Africa where strong currents prevail in a N-S direction, binning and stacking methodology was used to ensure a thorough reflection of the subsurface. The high elevation changes in the mountainous region of Yemen called for a special array design, dual elevation and hybridstatic routines, while under the dunes of Algeria, the low relief structures needed proper accounting of static variation through modeling. This paper outlines the various technical challenges faced in the above regions and the solutions that were designed for them. While specific solutions are required in special circumstances, PETRONAS underlying objective is to acquire optimal data that will last the life cycle of a field where the surveys form the base cases for eventual reservoir monitoring through 4D seismics. Imaging through gas clouds, detection of fractures and improving resolution of thin pay sands and seals are some of our continuing challenges. With strong focus on proactive resolution of technical issues, the operational challenge of striking the right balance between quality, cost and efficiency is managed. Health and safety and preservation of the environment during seismic operations remain as an underlying principle of PETRONAS.

This is the first of two papers describing the application of simulator-optimization methods to a natural gas storage field development planning problem. The results presented here illustrate the large gains in cost-effectiveness that can be made by employing the reservoir simulator as the foundation for a wide-ranging search for solutions to management problems. The current paper illustrates the application of these techniques given a deterministic view of the reservoir. A future paper will illustrate adaptations needed to accommodate uncertainties regarding reservoir properties.

The most widely used method of thermal oil recovery is by injecting steam into the reservoir. A well-designed steam injection project is very efficient in recovering oil, however its applicability is limited in many situations. Simulation studies and field experience has shown that low injectivity reservoirs and small thickness of the oil-bearing zone limit the performance of steam injection. This paper discusses alternative methods of transferring heat to heavy oil reservoirs, based on electromagnetic energy. We present a detailed analysis of low frequency electric resistive (ohmic) heating and higher frequency electromagnetic heating (microwave frequency). We show the applicability of electromagnetic heating in two example reservoirs. The first reservoir has thin sand zones separated by impermeable shale layers and viscous oil (9541 cp at initial reservoir conditions). We model preheating the reservoir with low frequency current using two horizontal electrodes, before injecting steam. The second reservoir has low permeability and oil viscosity of 33 cp at initial reservoir conditions. In this case we use a high frequency microwave antenna located 30 ft from the producing well as the heat source. Simulation results presented in this paper suggest that electromagnetic heating may be a good stimulation technique for heavy oil reservoirs with low injectivity or with thin payzones. We identify the parameters which are critical for electromagnetic heating. We also discuss past field applications of electromagnetic heating as well as technical challenges and limitations.

The technology of drilling and production of horizontal wells is probably one of the most significant breakthrough in the oil and gas industry of the eighties. What was considered ten years ago, as an exotic way of drilling has become reality. The continuous improvement of hardware equipment made horizontal drilling cost-effective technique for developing reserves, improving productivity and recovery in oil and gas reservoir. Horizontal well technology continues to be at the forefront of the oil industry. This paper will highlight the Saudi experience in horizontal drilling. The past ten years have been an exciting period for those who believed in horizontal drilling applicability in Saudi Arabia. At the end of the year 1997 over than 150 horizontal wells have been drilled in Saudi oil fields. There are four major horizontal well applications identified in Saudi Arabia oil fields; 1) Control of coning in relatively thin remaining oil column area, 2) Improving sweep efficiency of water flooding program, 3) Improving productivity rate in thin/tight reservoirs and 4) Saving in total development costs in conjunction with previous three applications. This paper presents the major areas of application of horizontal wells and more specifically the objectives of applying horizontal drilling in different Saudi oil fields. In this paper, the world horizontal drilling activities along with the Saudi experience will be covered. This paper surveys different field examples to show the application trends of horizontal well technology in both offshore and onshore oil fields. The main objective of this survey is to demonstrate the performance improvement of these oil fields after the application of horizontal well technology.

Abstract There is a steadily increasing demand for the use of jack-up units in deeper water and harsher environments. To be confident of their use in these environments there is a need for jack-up analysis techniques to reflect accurately the physical processes occurring. The common modelling of spudcan footings as pinned or as linear springs is an over-simplification of foundation behaviour, and can therefore lead to overconservative design. This paper details the implementation of a work hardening plasticity model for spudcan footings on dense sand (named Model C) into a dynamic structural analysis program (named JAKUP). The motivation for this is to have a balanced approach to the analysis of jack-up units, with the non-linearities in the structural, foundation and wave loading models all taken into account. Wave loading is considered using NewWave theory, and the importance of random wave histories shown by constraining the deterministic NewWave into a completely random surface elevation. Examples are shown to emphasize the differences in predicted extreme response according to the various footing assumptions: pinned, linear springs and Model C. The role of plasticity theory for modelling foundations will be highlighted. Further uses of JAKUP in the understanding of the extreme response statistics and reliability of jack-up platforms are discussed. This paper is directed to those interested in the long-term reliability analysis of jack-up units. Introduction Jack-ups were originally designed for use in the relatively shallow waters of parts of the Gulf of Mexico. Due to their economic importance within the offshore industry, there has been a steadily increasing demand for their use in deeper water and harsher environments1. There is also a desire for a longer lasting commitment of a jack-up at a single location, especially in the role of a production unit2. To be confident of their use in these environments, there has been a need for changes in analysis techniques to make them more accurate, avoiding unnecessary conservatisms which were once commonplace. More realistic modelling of jack-ups, based upon the relevant physical processes has been developed in a number of areas, the most significant being;dynamic effects,geometric non-linearities in structural modelling,environmental wave loading,models for foundation response. There has been considerable diversity in this development, with studies using varying levels of complexity for different aspects of the analysis. This is especially true for soil/structure interaction, with some studies using detailed structural models or advanced wave mechanics, whilst still using the simplest of foundation assumptions (i.e. pinned footings)3,4,5. The purpose of this paper is to describe a more balanced approach to the analysis of jack-up units. The components of a dynamic structural analysis program, named JAKUP, which is capable of considering the major non-linearities in jack-up response, are described. The motivation for this development is to achieve confidence in all of the components affecting the response. The principal characteristics of the structural, foundation and wave loading models are detailed, and example calculations given. Lastly, a discussion of the applications of these models is presented.

Abstract Sustainable Energy Solutions has been developing Cryogenic Carbon Capture™ (CCC) since 2008. In that time two processes have been developed, the External Cooling Loop and Compressed Flue Gas Cryogenic Carbon Capture processes (CCC ECL™ and CCC CFG™ respectively). The CCC ECL™ process has been scaled up to a 1TPD CO2 system. In this process the flue gas is cooled by an external refrigerant loop. SES has tested CCC ECL™ on real flue gas slip streams from subbituminous coal, bituminous coal, biomass, natural gas, shredded tires, and municipal waste fuels at field sites that include utility power stations, heating plants, cement kilns, and pilot-scale research reactors. The CO2 concentrations from these tests ranged from 5 to 22% on a dry basis. CO2 capture ranged from 95−99+% during these tests. Several other condensable species were also captured including NO2, SO2 and PMxx at 95+%. NO was also captured at a modest rate. The CCC CFG™ process has been scaled up to a .25 ton per day system. This system has been tested on real flue gas streams including subbituminous coal, bituminous coal and natural gas at field sites that include utility power stations, heating plants, and pilot-scale research reactors. CO2 concentrations for these tests ranged from 5 to 15% on a dry basis. CO2 capture ranged from 95−99+% during these tests. Several other condensable species were also captured including NO2, SO2 and PMxx at 95+%. NO was also captured at 90+%. Hg capture was also verified and the resulting effluent from CCC CFG™ was below a 1ppt concentration. This paper will focus on discussion of the capabilities of CCC, the results of field testing and the future steps surrounding the development of this technology. Cryogenic Carbon Capture (CCC) Since 2008 Sustainable Energy Solutions has developed a process called Cryogenic Carbon Capture (CCC). The CCC process is a true bolt-on technology that can easily be retrofit on virtually any stationary emission source without modification to the boiler, turbine, or steam piping.

A facility blowdown in the oil and gas industry is a safety critical operation; required to ensure the safe shut-down of processing facilities during a plant emergency. In a full facility blowdown operation, the entire plant is isolated into a number of segments and then depressurized into the facility’s flare system. The outcome of a blowdown event is dependent on the performance of a number of safety critical control system and final elements in the plant; these are designed to ensure the safe and successful depressurization of the plant without any conspicuous incidents. Blowdown events are inherently fast transient processes, reliant on a large number of valve opening and closing operations with rapid reduction in pressure and temperature. It is critical to ensure that the process is depressurized quickly enough (cf. API 521) but whilst respecting constraints such as minimum design metal temperatures, accoustic and flow induced vibration limits in flare tailpipes and back-pressure constraints throughout the flare system. Blowdown incident investigations typically involve a critical review of the plant historian data and require dynamic simulation studies to adequately assess the event so as to determine whether the blowdown operation proceeded as planned, that no design constraints were violated and to glean any process safety lessons that can be learnt. In this paper, with reference to a number of recent events on oil and gas facilities, we explain how to carry out a comprehensive blowdown investigation. We discuss a number of case studies from facilities in different parts of the world, including those that have shown operational deviations such as non-closure/partial closure emergecy shut down valves, delays in opening or non-opening of BDVs, and mal-functioning check valves. Some of these deviations caused flare capacity issues in the plant, minimum design metal temperature violation risks to process drums, unexpected pressurization of process drums, flow reversal into low pressure segments causing near miss events, and other violations of recommended practice. We explain how these studies have helped understand the current state of the plant’s safety systems and have been used by operating companies to identify design and operational changes critical for safe plant operation. Finally we discuss how these studies provided input to plant maintenance personnel in order to help prioritize maintenance activities and to make prudent maintenance investment.

The reduction in sea ice in the Arctic has produced new routes for shipping, thereby increasing the amount of marine traffic that can transit through the area. Additionally, the Arctic has become a popular destination for cruise ships some of which are increasingly large capacity ships that are operating a great distance from search and rescue assets and other assistance. If a marine accident were to occur in the Arctic and people became exposed to the elements then the clothing they could use may not provide sufficient thermal protection while waiting for rescue. This paper contains the results from two studies. The first measured the amount of thermal protection provided by various clothing ensembles that could be used in a mass Arctic evacuation, which were then used to calculate predicted survival time (PST). The second study evaluated the length of time a person may be exposed to the environment if they were forced to abandon a vessel or installation at one of eight different locations in the Arctic. These exposure times are based on the range of times search and rescue assets would take to reach the individual. The results from these two previous studies were combined to provide recommendations for clothing ensembles for different locations in the Canadian Arctic while awaiting rescue. The estimated exposure time while awaiting rescue varied considerably, ranging from a minimum of 14 hours to a maximum of 261 hours. In certain conditions, the thermal protection provided by eight of the ten clothing ensembles tested was sufficient to delay death from hypothermia. However, it should be noted that if PST is greater than 36 hours then factors other than hypothermia are likely to result in death (e.g. drowning or dehydration). The majority of the ensembles did not provide a sufficient level of thermal protection to prevent death from hypothermia in less than 36 hours when wetted and exposed to wind. It is concluded that certain clothing ensembles that could be used during a marine accident in the Arctic would not provide sufficient thermal protection to survive exposure to the environment while awaiting rescue. This finding is particularly important given the relatively recent increase in marine traffic through the Arctic and the subsequent increase in the likelihood of a marine accident that may require abandonment and result in direct exposure to the environment., Arctic Technology Conference, 24-26 October 2016, St. John's, NL, Canada

This paper describes a numerical method of ship-ice interaction. Identifying an operational risk to an ice breaking vessel such as serious interference or sudden efficiency reduction by ice is necessary at early design stage. CFD-DEM coupled approach can be used for this prediction. Combining two numerical approaches, free floating ice particles can interact with the surrounding fluid as well as the rigid hull surface effectively. Ship-ice interaction becomes more complicated around the stern area considering the swirling flow of the propulsion device and the complex hull appendages. Using CFD-DEM method, simulation of ship-ice interaction during the astern operation was carried out. To evaluate the simulation performance, three example cases were conducted. The first and second case is the astern operation with/without the propeller action. For reducing the computational load, a virtual disc model for the propeller action is selected. Then, a simple sensitivity analysis on the ice friction coefficient was carried out to verify if the friction model is working appropriately. CFD-DEM simulation provides a promising result showing a similar ice jamming and pileup pattern with the physical model test. The suggested method can help to understand the ice movement effectively including the hydrodynamic force and the contact dynamics together., Arctic Technology Conference, October 24, 2016, St. John's, Newfoundland and Labrador, Canada

N.R. Warpinski, SPE, Sandia Natl. Labs, and P.T. Branagan, SPE, and R.E. Peterson, SPE, Branagan & Assoc., and J.E. Fix, SPE, James E. Fix & Assoc., and J.E. Uhl and B.P. Engler, Sandia Natl. Labs, and R. Wilmer, Branagan & Assoc. Copyright 1997, Society of Petroleum Engineers, Inc. Abstract Six hydraulic-fracture injections into a fluvial sandstone at a depth of 4300 ft were monitored with multi-level tri-axial seismic receivers in two wells and an inclinometer array in one well, resulting in maps of the growth and final geometry of each fracture injection. These diagnostic images show the progression of height and length growth with fluid volume, rate and viscosity. Complexities associated with shut downs and high treatment pressures can be observed. Validation of the seismic geometry was made with the inclinometers and diagnostic procedures in an intersecting well. Fracture information related to deformation, such as fracture closure pressure, residual widths, and final prop distribution, were obtained from the inclinometer data. Introduction Contrary to expectations based on simple models, hydraulic fracturing is proving to be a complex process that is still not adequately represented by theory. The reason for this is clear, as models assume that the earth is a homogeneous isotropic continuum when in fact the reservoirs which are fractured are highly discontinuous and variably anisotropic and heterogeneous. Since current models are incapable of dealing with this complexity in anything but an ad hoc manner, further understanding of hydraulic fracturing is not likely to progress very rapidly without an ability to measure, image, or observe fracturing processes under in situ reservoir conditions. A glimpse at the complexity of fracturing in real reservoirs is now available from several cores through hydraulic fractures, from limited mineback experiments, and from various diagnostics. From these relatively few measurements, complex features such as multiple fracture strands, secondary fractures, T-shaped fractures, redirection of fracture orientation due to production, inefficient growth across bedding, complex proppant transport, and other unexpected features have been seen. From this limited sampling, one would conclude that the fracturing process is poorly represented by most models. However, it should also be stressed that the results found at the end of a treatment (e.g., as in a cored or mined-back fracture) may not be a good representation of the actual process during fracturing, since all complexities will be seen whether or not they had any significant effect on the mechanics of the process. Separating out irrelevant features is difficult using only post-fracture snapshots of the process. For the reasons noted above, it is clear that the optimum diagnostic would provide a real-time continuous image of the fracture growth process. Currently, there is no envisioned technology for directly viewing the fracture, but some fracture parameters can be indirectly monitored using downhole seismic receivers and downhole inclinometers. The application of these two technologies in the C-sand interval at the M-Site facility is the subject of this paper. M-Site The M-Site field experiments, located at the previous Multiwell Experiment site in the Piceance basin of Colorado, are co-funded by the Gas Research Institute (GRI) and the US Department of Energy. Details of the M-Site layout and instrumentation are given in previous papers and are only briefly repeated here. The reservoirs undergoing testing are fluvial Mesaverde sand-shale sequences, so the technologies developed in this difficult environment are translatable to many other reservoirs. Results of previous tests are found in several papers and reports. A plan view of the site is shown in Figure 1 and a schematic of the well, instrument, and sandstone layout are given in Figure 2. P. 87^

Abstract An accurate method to predict volumetric behavior of gas mixtures, such as in the case of underground gas storage where the in-situ gas is mixed with the injected gas, is presented in this paper. This method accurately calculates the compressibility (Z) factor of pure hydrocarbon, non-hydrocarbon gases and gas mixtures. These calculations are based on correction functions developed from correlation of data (Z-factor) generated by the Peng-Robinson equation of state. The correction functions are function of gas composition, pressure and temperature, so the Z-factor can be calculated explicitly from gas composition under different reservoir conditions. Several comparative examples are presented to compare the Z-factors calculated by the correction functions with those calculated by the Peng-Robinson equation of state (PR-EOS) and with measured data published in the literature. The comparison results indicated that the average absolute relative deviation (AARD) is 3% for gas mixtures, 2% for pure hydrocarbon, non-hydrocarbon gases and less than 1% for pure components (methane, nitrogen, carbon dioxide). A stable method of calculating Z-factor for gases from their composition is presented. This method is iteration free so the CPU time is minimized. Accurate values of Z-factor can be calculated which are better than those obtained by linear interpolations. The correction functions can be incorporated in any non-compositional simulator to calculate the Z-factor directly without any iterative procedures which occur in compositional simulators during the calculations of Z-factor using the equation of state. These functions also eliminate the inaccurate linear interpolations of tabulated Z-values, specially during calculations of Z-factor for gas mixtures, in non-compositional simulators. Introduction The compressibility factor is an important property for gases to calculate volume (material) of gases under given conditions (pressure, temperature). Also the Z-factor is important parameter to calculate other gas properties such as the formation volume factor and the coefficient of isothermal compressibility. It is important to calculate the Z-factor more accurately, specially for gas mixtures, in order to predict the volumetric gas behavior more reasonably. In compositional simulators the calculations of the Z-factor are accurate, but for every condition the cubic equation of state is solved for Z-factor. The solution procedure involves iterations such as in Newton Raphson method. These iterations and convergence checking procedure consumes, some times, a considerable part of CPU time for just calculating gas properties (Z-factor). The CPU time should be used more efficiently in and wisely in the simulator. On the other side in the non-compositional simulators the Z-factor values are tabulated for certain gas composition and pressures and a linear interpolation procedure is used to calculated those Z-factor values which are not listed in the table. This procedure leads to erroneous calculations of Z-factor specially for gas mixtures where the linear interpolations are no longer accurate. The calculation procedure of Z-factor using the correlation functions presented in this paper has two advantages: Obtaining an accurate value of Z-factor and saving CPU time for other more important calculations in the simulator. Background Some impurities such as nitrogen and carbon dioxide are often existed in appreciable amounts in natural gases. The Z-factor for non-hydrocarbon components of natural gas in certain corresponding states differ markedly from those of hydrocarbons. This makes the non-hydrocarbon and hydrocarbon components not quit additive. Eilerts, Muller and Carlson studied the compressibility of natural gas and nitrogen mixtures. They proposed a method to calculate the Z-factor for the gas mixture by introducing a correction factor into the additive form as shown in Eq. 1. (1) where: Zm = actual Z-factor for gas mixture, Zn = Z-factor of the nitrogen in the mixture, Zn = Z-factor of hydrocarbon gas, n = mole fraction of nitrogen in the mixture. P. 453^

Abstract Independent Oil & Gas operators are playing an increasingly important role in the production of hydrocarbons in the United States. Advanced reservoir management techniques, especially approaches based on advanced computer modeling, have been successfully applied by major producers to many oil and gas fields, but have not been particularly accessible to Independent operators. These tools are expensive and often technologically incomprehensible to the small operator. The Internet, which is revolutionizing the way business is conducted in many venues, may offer a way to surmount the problems associated with the cost and accessibility of reservoir management software. This paper will illustrate, through actual case studies involving Independent operators, a paradigm which brings together local consultants, software vendors, expert users (specialized consultants), and Independent operators using the World Wide Web (W3) to pursue low cost reservoir evaluation and planning. Moreover, it will demonstrate how meaningful geological and engineering modeling (reservoir simulation) access can be provided directly to Independent operators who are not modeling experts. This is accomplished by task-distributed computing, which allows computing and databases on individual computers to be managed by a central server. The principal conclusion is that it may be possible to bring the technology of advanced reservoir characterization, including stochastic modeling and reservoir simulation to bear on the problems relevant to Independent operators at significantly lower cost utilizing the W3. The first phase of this project is complete and in place on the W3. Success factors for this approach include: willingness of software vendors to restructure pricing algorithms, security on the W3, acceptance of W3 by local consultants and Independent operators, improvements in W3 communications bandwidth. Introduction Reservoir management technologies have the potential to increase oil recovery while simultaneously reducing production costs. These technologies were pioneered by major producers and are routinely used by them. Independent producers confront two problems adopting this approach: the high cost of acquiring these technologies and the high cost of using them even if they were available. Effective use of reservoir management tools requires, in general, the services of a professional (geoscientist or engineer) who is already familiar with the details of setting up, running, and interpreting computer models. A previous paper described a project which alms to make reservoir management tools available to the Independent operator in a cost effective manner. The central feature of this approach exploits the potential of the World Wide Web (WWW) to deliver software access at low cost. The procedure of launching petrotechnical applications and retrieving results over the WWW, and the paradigm for the interaction between the independents, the petroleum service sector, and the government, were presented. It was emphasized that in contrast to the present situation, a non-expert Independent producer is able to make simple but meaningful changes to the simulation models, such as reconfiguring production or working over wells, in order to assess the effect of such strategies on oil recovery rates. This paper will illustrate this paradigm in action through an actual case study involving an Independent operator. Local consultants, software vendors, expert users (specialized consultants), and independent operators are brought together by the WWW to pursue low cost reservoir management. Meaningful geological modeling and reservoir simulation access is provided directly to independent operators who are not modeling experts. P. 685