bluuebunny/crossref_metadata_2025 huggingface dataset:
Heavy Oil Rheology as a Function of Asphaltene and Resin Content and Temperature
Authors: Argillier J-F. , Coustet C. , Hénaut I.
Published: December 2007

Because of very important reserves that are of the same order of magnitude than conventional oils, heavy oils represent a strategic source of hydrocarbons. The major difficulty for producing and transporting these crudes comes from their very high viscosities. The success of exploitation of these petroleum products requires new treatments to improve their transport. Such a target implies to better understand the relationship between the composition of heavy oils, in particular in terms of asphaltenes and resins content and their flow properties. Influence of asphaltenes content in the crude has been particularly studied in our lab : the experimental work revealed the existence of a critical concentration C* above which the asphaltenes particles overlapp. This structural change dramatically increases the viscosity and intensifies the elastic character of heavy crude oils. A further series of experiments has focused on the influence of resins: they show that in dilute regime (CC*), which corresponds to the case of a heavy oil, they lower the asphaltenes effect on viscosity. Experiments were first carried out with asphaltenes and nonylphenol as a model of resins and followed by experimental work on real crude that confirmed the trends. To understand the rheological behavior of a heavy crude oil in relation with its internal structure, asphaltenes and resins have to be simultaneously considered. From this study we conclude that the origin of the high viscosities of heavy oils comes from to the entanglement of solvated asphaltene particles stabilized by resin molecules. A strong influence of temperature on the rheology is also revealed by high activation energy measurements. This thermal dependent rheological behavior shows that the internal organization of the heavy crude oil is partly based on thermal dependent physical bonds. Using the reversibility of these physical links, we should be able to modify the structure of heavy crude oils to facilitate their transport.
Scalability of the Deterministic and Bayesian Approaches to Production Data Integration into Field-Scale Reservoir Models
Authors: Vega Leonardo , Rojas Danny , Datta-Gupta Akhil
Published: December 2007

Current techniques for production data integration into reservoir models can be broadly grouped into two categories: deterministic and Bayesian. The deterministic approach relies on imposing parameter smoothness constraints using spatial derivatives to ensure large-scale changes consistent with the low resolution of the production data. The Bayesian approach is based on prior estimates of model statistics such as parameter covariance and data errors and attempts to generate posterior models consistent with the static and dynamic data. Both approaches have been successful for field-scale applications although the computational costs associated with the two methods can vary widely. This is particularly the case for the Bayesian approach that utilizes a prior covariance matrix that can be large and full. To date, no systematic study has been carried out to examine the scaling properties and relative merits of the methods.

The purpose of this paper is twofold. First, we systematically investigate the scaling of the computational costs for the deterministic and the Bayesian approaches for realistic field-scale applications. Our results indicate that the deterministic approach exhibits a linear increase in the CPU time with model size compared to a quadratic increase for the Bayesian approach. Second, we propose a fast and robust adaptation of the Bayesian formulation that preserves the statistical foundation of the Bayesian method and at the same time has a scaling property similar to that of the deterministic approach. This can lead to orders of magnitude savings in computation time for model sizes greater than 100,000 grid blocks. We demonstrate the power and utility of our proposed method using synthetic examples and a field example from the Goldsmith field, a carbonate reservoir in west Texas.
Timestep Selection During Streamline Simulation via Transverse Flux Correction
Authors: Osako Ichiro , Datta-Gupta Akhil , King Michael J.
Published: December 2007

Streamline simulators have received increased attention because of their ability to effectively handle multimillion cell detailed geologic models and large simulation models. The efficiency of streamline simulation has relied primarily on their ability to take large time steps with fewer pressure solutions within an IMPES formulation. However, unlike conventional finite-difference simulators, no clear guidelines are currently available for the choice of time step for pressure and velocity updates. This has remained largely an uncontrolled approximation, either managed by engineering judgment, or by potentially time-consuming time step size sensitivity studies early in a project. This is clearly related to the lack of understanding of numerical stability and to the lack of error estimates during the solution.

We propose a novel approach for time step selection during streamline simulation that is based on three elements. First, we reformulate the equations to be solved by a streamline simulator to include all of the three-dimensional flux terms – both aligned with and transverse to the flow directions. These transverse flux terms are totally neglected within the existing streamline simulation formulations. Second, we propose a simple grid-based corrector algorithm to update the saturation to account for the transverse flux. Third, we provide a discrete CFL (Courant-Fredrich-Levy) formulation for the corrector step that leads to a mechanism to ensure numerical stability via the choice of a stable time step for pressure updates. This discrete CFL formulation now provides us with the same tools for time step control as are available within conventional reservoir simulators.

We demonstrate the validity and utility of our approach using a series of numerical experiments in homogeneous and heterogeneous !4 five-spot patterns at various mobility ratios. For these numerical experiments, we pay particular attention to favorable mobility ratio displacements, as they are known to be challenging to streamline simulation. Our results clearly demonstrate the impact of the transverse flux correction on the accuracy of the solution and on the appropriate choice of time step, across a range of mobility ratios. The proposed approach eliminates much of the subjectivity associated with streamline simulation, and provides a basis for automatic control of pressure time step within full field streamline applications.
Stabilized Finite Element Methods for Coupled Geomechanics – Reservoir Flow Simulations
Authors: Wan J. , Durlofsky L. J. , Hughes T. J. R. , Aziz K.
Published: December 2007

Coupled geomechanical-fluid flow models are needed to account for rock deformation resulting from flow-induced pressure changes in stress sensitive reservoirs. There are, however, issues of numerical stability that must be addressed before these coupled models can be used reliably. Specifically, it is known that standard procedures can lead to pressure oscillations as a result of the violation of the Babuška-Brezzi (B-B) condition, which requires unequal order interpolation of the displacement and pore-pressure variables. In this paper, a number of different types of coupled models are considered. A novel finite element method is developed to circumvent the B-B condition. The method applies a stabilized finite element technique to solve the force balance and pressure equations along with a finite volume method to solve the remaining component mass balance equations. All of the equations are solved in a fully coupled fashion. This method is compared with fully coupled and iteratively coupled models developed using non-stabilized finite elements for the force balance with finite volume methods for all of the component mass balance equations. These comparisons demonstrate that all methods perform reliably on homogeneous reservoirs over long time scales. The stabilized method is shown to provide improved stability at early times and for reservoirs with very low permeability barriers.
Integrated Optimization for Rate Allocation in Reservoir Simulation
Authors: Davidson Jeffrey E. , Beckner Bret L.
Published: December 2007

When using a reservoir simulator to predict future field production, one must establish operating rules and procedures to manage wells and surface facilities. In EMpower™, Sequential Quadratic Programming (SQP) methods are used to set well rates in a facility network of a reservoir simulator so that production objectives are maximized subject to constraints on pressures, flow rates and stream compositions. Actions taken for infeasible conditions are discussed. Black-oil and compositional examples are given.
New PDC Design Process Solves Challenging Directional Application in Abu Dhabi Onshore Fields
Authors: Al-Suwaidi Abdullah S. , Soliman Ahmed Abou , Klink Zeinoun , Isbell Matt , Dykstra Mark , Jones Christopher
Published: December 2007

Roller cone bits have dominated the 8–1/2" steerable application in Abu Dhabi due to their proficient steerability, consistently achieving the required build rates in the soft Nahr Umr shale. In the vertical section, PDC bits often achieve up to four times the penetration rates of TCI bits. However, directional performance when using PDC bits to build angle was compromised by fluctuations in reactive torque resulting in poor tool face control and inconsistent build up rates. The overall result was poor penetration rate and performance compared to roller cone bits. The operator and a service company utilized a new design process and cross functional team approach to aggressively seek new steerable PDC technology to drill the curved section with controllable torque response and consistent directional behavior while achieving the full penetration rate advantage of PDC bits. This process was complemented by the Well Delivery Limit process (WDL) that was already established by the operator that focused on delivering high value wells with significantly reduced costs. The team analyzed the drilling operations from virtually every perspective using numerical models, laboratory drilling tests, and field testing. The key to the PDC solution was the team process that identified the relevant drilling problems and performance requirements in order to develop the needed technology. After 30 bit runs from November 2001 to June 2002, the team reduced drilling costs by $44.26 per foot for a total savings of $3,792,367 over 85,682 ft and 2,386 drilling hours. The average ROP for the section doubled from 18 ft/hr with TCI bits to 36 ft/hr. The current ROP record stands at 60 ft/hr over a 3,169 ft interval.
New, Stable PDC Technology Significantly Reduces Hard Rock Cost Per Foot
Authors: Schell Edward J. , Phillippi Duane , Fabian Robert T.
Published: December 2007

Historically, the hardest and most abrasive rock formations, such as the Travis Peak, Hosston, and Bossier Sands areas of East Texas and North Louisiana, were drilled almost exclusively by roller-cone insert bits. With some exceptions, the only polycrystalline diamond compact (PDC) runs were small-diameter holes where the formation was predominantly comprised of shale and limestone. Significant advances in design and cutter technology in PDC bits during the past 5–10 years have made it possible for PDC to be used more frequently on the fringes of these hard rock intervals.

Combining advanced PDC bit designs with state-of-the-art cutter technology has opened up many new applications for PDC bits that were once only appropriate for IADC Series 6, 7, and 8 insert drill bits. Because of this new technology, PDC has become a practical alternative for drilling hard rock, providing a significant reduction in cost per foot. Combining new, highly abrasion-resistant PDC cutters with competent stable bit designs that provide both low torque and dynamically stable characteristics was the key to this development.

Several case histories of hard rock drilling using PDC bits will be discussed in this paper, illustrating the reduction in costs. These case histories demonstrate, through descriptions of trial and error, the problems associated with these new PDC applications and how they were overcome.
Gulf of Mexico Performance Fluids Management Implementation – Seven-Step Process
Authors: Rojas J. C. , Schonacher D. , Hudson C. , Gharst J. , Paiuk B. , Billon B.
Published: December 2007

BP's Gulf of Mexico (GoM) Operations have determined that the reduction of oil-on-cuttings (OOC) from 14% to less than 6.9% would provide the best opportunity to minimize the environmental impact of drilled cuttings discharge base on currently available technologies. Meeting the GoM NPDES environmental regulations, while simultaneously improving drilling performance drove the implementation of a Performance Fluids Management (PFM) process. Created within BP, PFM is a management process that integrates fluids and waste management. The new GoM cuttings discharge regulation (max 6.9% oil on cuttings) was met without adversely impacting drilling operations, while also reducing fluid cost by 8% ($3.5 MM) in 2001.

This paper discusses the development and application of the PFM process. The authors will present the key components of PFM, which include implementation of a common format for fluid management programs, end-of-well recaps, a weekly PFM report capturing agreed upon performance targets, the PFM audit process, skill assessment for fluids and PFM engineers, and a model to predict accurate PFM cost/volumes generated. The PFM process has been implemented in Colombia, Bolivia and Argentina where it delivered similar savings. The process currently is being implemented in Trinidad. The process is applicable to wells in excess of $7–10 million total cost. The potential fluid cost reduction associated with a global PFM implementation will be around 10–15% ($20–25 million/year).
Multistation Analysis and Geomagnetic Referencing Significantly Improve Magnetic Survey Results
Authors: Lowdon R. M. , Chia C. R.
Published: December 2007

Improvements in the quality of wellbore directional surveys using multistation analysis and geomagnetic referencing are demonstrated, with case studies to illustrate the benefits to drilling projects. Multistation analysis is a technique that provides compensation for drillstring magnetic interference. The benefits of multistation analysis can be further improved when used in conjunction with geomagnetic referencing, which takes account of localized crustal effects in the earth's magnetic field.

In recent years these improved magnetic surveying techniques have gained increased industry acceptance. Their practical application is delivering the capability to reach tighter drilling targets, and in some circumstances to dispense with the need to run gyro surveys. These techniques are providing tangible and cost saving benefits to help meet the demanding technical and economic needs of these projects.

A series of well profiles for wells drilled on projects that use these techniques are presented, each of which use individually mapped local crustal magnetic field models and different drilling assembly configurations. Treatment of each of the major magnetic surveying error sources is discussed, and the effect on surveyed well position when compared with independent overlapping gyro surveys is presented.

The benefits from this real-time drilling surveying process also demonstrate the value of the "drilling correction" as a means of drilling more accurately to plan, with a reduced need for correction runs, or post-drilling changes to the planned well trajectory.
Casing Drilling Activity Expands in South Texas
Authors: Fontenot Kyle , Highnote Joe , Warren Tommy , Houtchens Bruce
Published: December 2007

Conoco has had a sustained, multi-rig, development program in the Lobo field of South Texas since the mid-1990's. Drilling efficiency using conventional techniques has improved to the point where additional gains are difficult to achieve. Drilling with casing was implemented as a potential way to provide a step change to drilling performance in this mature field. The Casing Drilling* process has proven to significantly reduce the in-hole trouble time below the low value that was already obtained and has demonstrated the ability to further reduce drilling costs.

The first two phases of the Lobo Casing Drilling program were conducted with a dual-purpose (Casing Drilling/conventional drilling) rig. After drilling 22 wells, the Lobo Casing Drilling program is being expanded by replacing this rig with three new Casing Drilling rigs designed to further optimize Casing Drilling performance. The first of these rigs is on location and the other two will begin operations by the end of 2002.
Maintaining Well Productivity through Deployment of a Gas Lift Scale Inhibitor: Laboratory and Field Challenges
Authors: Fleming N. , Stokkan J. A. , Mathisen A. M. , Ramstad K. , Tydal T.
Published: December 2007

This paper will focus on the laboratory and field challenges of maintaining productivity in a North Sea well through scale inhibitor deployment via gas lift. Calcium carbonate scale formation commonly occurs during early production of formation water and in this particular well was detected on the downhole safety valve and upper tubing. Several scale management options were considered, however, that considered most likely to succeed was inhibitor injection via the gas lift system.

An extensive laboratory evaluation under the North Sea field downhole conditions was undertaken in order to qualify a suitable scale inhibitor/solvent package. While the identification of a scale inhibitor capable of controlling calcium carbonate was relatively simple, the combination of an aqueous based inhibitor with a suitable solvent package proved challenging. The initial product development stage was focused towards identifying compatible blends of various types of scale inhibitors (phosphonates, polymers and vinyl sulphonate copolymers) with different solvent and solvent mixtures. An essential aspect of the formulation design was to minimise the potential for volatile loss from the product to the dry injection gas.

Several candidate scale inhibitor/solvent packages were put through a rigorous laboratory evaluation programme under the harshest possible conditions likely to be experienced in the field. From this initial review products were identified as passing pre-defined criteria and showed good environmental qualities with very low viscosities (5cP or less at ambient temperature) before and after volatile loss and had very low corrosivity (0.01mm/y). In addition, the chemicals displayed complete compatibility at concentrations in excess of 50% with the completion fluid, formation water and completion elastomers, and controlled calcium carbonate scaling at a relatively low concentration.

The final part of the paper will provide details of the field deployment experiences and challenges of the gas lift scale inhibitors developed.
Fighting Naphthenate Deposition at the Heidrun Field
Authors: Vindstad Jens Emil , Bye Arne S. , Grande Knut V. , Hustad Britt M. , Hustvedt Egil , Nergård Bjørn
Published: December 2007

At the Statoil-operated Heidrun-field in the Norwegian Sea, naphthenate deposits were first observed during a maintenance shutdown in September 1996. Thereafter the problem increased, and by the end of 1997 it was recognised as a constant threat against continuous production. The present paper describes both the short-term measures taken to gain control of the problem in the early days, and the quest for a more elegant long-term solution. Statoil is continuously working to increase its fundamental understanding of the naphthenate problems and to improve the naphthenate inhibitors used at the Heidrun field.
The Interaction of Flow and Reactions in Porous Media
Authors: Woods A W , Jupp T E , Richardson C N
Published: December 2007

As water migrates through porous rock, any changes in pressure or temperature, as well as changes in fluid composition, may lead to changes in the solubility of dissolved minerals. We examine the reactions which may develop in such a system, following the injection of water of one temperature and composition into a reservoir with different temperature and equilibrium composition. We examine the structure of pressure, temperature and compositionally induced reactions.
Development of a Suitable CaCO3 Scale Inhibitor System for use in Ultrahigh Temperature and Pressure Wells
Authors: Wylde J. J. , McKay S. F. , Falla M.
Published: December 2007

This paper reports a case study on the selection of a HP/HT/HS scale inhibitor for CaCO3 precipitation in the ultrahigh temperature and pressure environment experienced in the TotalFinaElf Elgin-Franklin assets. The paper will outline the scale management, inhibitor selection and deployment strategies adopted for scale control in this extremely harsh environment. The downhole temperature in these wells can be up to 200ºC and pressures can exceed 16000 psi. Problems are further enhanced by large decreases in pressure over relatively short changes in well depth. The literature is scant on studies performed at these conditions and a thorough screening of a wide range of scale inhibitor products and deployment techniques is an essential asset to the continued exploitation of very harsh well conditions.

A new, upgraded scale prediction routine has shown that CaCO3 precipitation will occur over the whole range of reservoir conditions. A wide range of scale inhibitor chemistries including sulphonated polymers, phosphonates and some novel development products have been screened using four industry standard techniques. Thermal ageing revealed any instability caused by thermal degredation of the inhibitor molecule and jar test compatibility experiments performed at field temperature showed chemical incompatibilities with field brines. Dynamic scaling loop experiments were performed on not only the fresh inhibitor chemistries but also on thermally aged samples. The thermally aged samples were also analysed spectroscopically to identify any breakdown products and mechanisms. Finally coreflood experimentation was used to highlight inhibitor return profiles over a simulated squeeze treatment and to look for any formation damage that may have occurred.
Critical Success Factors for Technology Transfer: Sharing a Perspective
Authors: Badruzzaman Ahmed
Published: December 2007

The paper describes three examples from the author's experience of technology transfer in the E&P industry and examines a number of critical elements, beyond those normally found in the literature, that need to be accounted for to bring about a successful and durable transfer of a technology. These include meticulous planning, determination of appropriateness, recipient buy-in, an early demonstration of benefits, at least a nascent technology base and awareness, continuous mentoring and monitoring, and finally evolution into a culture of technology utilization and management.
The Different Condensate Gas Recovery Using Gas Oil Permeability and Gas Condensate Permeability Curve
Authors: Chang Su , Ping Guo , Li Shilun , Guo Xiao , Sun Liangtian , Sun Fengjing
Published: December 2007

Till now, condensate reservoir engineers in China used substitute permeability curve, measured by unsteady-state method using model oil (kerosene etc.) and model gas (nitrogen etc.) system, to be basic input curve in numerical simulation and well testing. The typical interfacial tension of the model fluid system is about 30mN/m, which is much higher than true condensate system. The objectives of the work presented in this paper, were measuring relative permeability of condensate system and model fluid system, comparing their differences and resultant condensate gas recovery differences. The experiments employed true condensate system and formation core and were based on measurement of basic core and fluid properties, preliminary compositional simulation of fluid behavior. The measurements showed that the relative permeability curves to the gas condensate system are quite different to curves of model gas/oil system, and a relative permeability rate effect for both condensate oil and gas was observed, with the relative permeability of both phases increasing with an increase in flow rate. The CMG one-dimensional radial simulation results showed that the resultant condensate oil and gas recovery of condensate gas oil permeability curves are both largely different from those of model gas/oil permeability curves. The study highlights the need to use condensing fluids when measuring gas condensate relative permeability.
Identification of Initial Gas Net-Pay in Deltaic Reservoirs Using Wireline Acoustic Measurements
Authors: Larrouquet F. , Gautama A. , Moinard L.
Published: December 2007

In the Mahakam delta in East Kalimantan, TotalFinaElf E&P Indonésie operates fields with numerous multi-layer reservoirs deposited within a deltaic environment. Formation waters in these reservoirs have very low salinities, which vary with depth and from reservoir to reservoir. When a field is in production, the evaluation and update of initial hydrocarbon net-pay is made more difficult by depletion and fluid level changes, which are related to channel reservoirs connectivity, both laterally and vertically. A new method has been developed, based on acoustic measurements, to help identify the original gas net-pay.

This method uses the fact that compressional acoustic waves travel slower in gas than in liquid whereas shear waves are not affected by fluids in the pore space. An empirical correlation is established between Vp/Vs ratio and shear slowness in known liquid-bearing sands. This correlation is used to predict Vp/Vs over the whole logged interval. A large difference between predicted and measured Vp/Vs indicates the presence of gas. Since gas is very compressible, the effect is noticeable even at very low gas saturations, i.e., in gas reservoirs that have already been depleted, or even swept by water.

The method was first tried in a mature oil field in order to distinguish gas from liquid and gave encouraging results. It was then applied in a gas field where a 3000-meter interval of dipole sonic log had been recorded in one well. Fluid status identified by this method was crosschecked against all other data (wireline logs, mud logs, wireline fluid samples) and against the geological model. The results helped confirm (or revise) the model, which, in turn, improves mapping, material balance calculations and optimization of production.

Based on numerous examples, the conclusion is that very good results are obtained in clean sands, especially where known water and gas bearing intervals are available for calibration. The article also states the limitations of the method, which can give ambiguous results in very shaly reservoirs and also fails in deep reservoirs where porosity falls significantly below 15 percent.
Well Pressure Behavior of a Finite-Conductivity Fracture Intersecting a Finite Sealing-Fault
Authors: Escobar Freddy H. , Tiab Djebbar , Berumen-Campos Sergio
Published: December 2007

Hydraulic fracturing is important to the development of low permeability reservoirs. Recent advances in the technology of hydraulic fracturing, coupled with its economic success, have led to its application in high permeability reservoirs. Consequently, fracturing is now applied in all types of formations including highly faulted systems. The existence of a fault near a well may impede or contribute to the fracture extension process. Various models and techniques have been introduced in the literature for the interpretation of transient pressure behavior of vertically fractured wells. However, none of the current models and techniques has taken into account the case of a fracture intersecting a fault.

This paper presents a theoretical model for analyzing the pressure behavior of a finite-conductivity vertical hydraulic fracture intersected by a sealing-finite fault, considering different angles of intersection and neglecting in all cases wellbore and fracture storage effects. The point at which fracture and fault conjoint has also been a matter of analysis in this study. The model was solved numerically using PEBI grids.

For the case where the fracture-fault system form an angle of 90 or 75°, the pressure response is characterized by a maximum point or "hump" in the pressure derivative which takes place once the transient response of the fracture has vanished. This is because the fault delays the development of the pseudoradial flow regime. For smaller angles, a peak is not observed; however, there is a transition period that causes an apparent pseudoradial flow to develop earlier. This is because the hump tries to develop but the fault is not long enough for that to happen. When the fault is very long (LD > re), pseudoradial flow does not develop because the fault acts as a boundary. A horizontal line on the pressure derivative curve is observed which can be easily confused with that of the actual pseudoradial flow regime. Correlations to estimate both fault length and fracture-fault angles are presented. A simulated example is presented to illustrate the proposed step-by-step procedure for interpreting a post-fracture pressure test of well near a sealing-fault.
Mercury and the Results from the Gulf of Mexico Offshore Operations Experiment (GOOMEX)
Authors: Boatman Mary C.
Published: December 2007

Surface sediment samples were collected from five platforms in the Gulf of Mexico during the Gulf of Mexico Offshore Operations Monitoring Experiment (GOOMEX), a Minerals Management Service funded study, and analyzed for total mercury. While this study was reported in 1995, new interest in the report was sparked by several newspaper articles using the results to link mercury in drilling discharges with mercury in fish. As part of the study program, sediment samples were collected from near the platform and far from the platform. Total mercury ranged from not detected to 3.5 parts per million in the sediments. The highest values were from near a single platform where discharges are shunted to within ten meters from the bottom. Tissue samples, including shrimp, crabs, fish livers, and fish stomach contents, were also collected as part of the project and analyzed for total mercury. Statistical comparison of the results indicated that the samples did not differ significantly between near field and far field. This presentation includes a background discussion of the issue of mercury as a global pollutant and puts into perspective the contribution from oil and gas activities around platforms.
Concentrations of Total Mercury and Methylmercury in Sediment Adjacent to Offshore Drilling Sites
Authors: Trefry John H. , Trocine Robert P. , McElvaine Michelle L. , Rember Robert D. , Hawkins Lucas
Published: December 2007

This paper presents results from a study of concentrations of total mercury (Hg) and methylmercury (MeHg) in seabed sediments near six offshore drilling sites in the Gulf of Mexico. Surface (0-2 cm) and subsurface (2-20 cm) sediment samples for this study were collected within three zones at each drilling site: <100 m (nearfield), 100-250 m (midfield) and >3 km (farfield). Total Hg levels in sediments from this study range from 11-92 ng/g (parts per billion, dry weight) for all farfield (background) samples and 25-558 ng/g for all nearfield samples. Concentrations of total Hg are significantly higher at nearfield stations than at farfield stations for five of the six drilling sites due to inputs from drilling discharges. Concentrations of MeHg range from 0.11-1.05 ng/g for all farfield sediments and <0.03-2.7 ng/g for all nearfield sediments. In contrast with results for total Hg, concentrations of MeHg in surficial (0-2 cm) sediments from all six drilling sites do not vary significantly between nearfield and farfield stations. Statistical comparisons of MeHg levels in nearfield versus farfield sediments at the six drilling sites, along with data from two of those sites that show lower levels of MeHg in some nearfield sediments than in farfield sediments, suggest that elevated levels of MeHg in sediments around drilling sites are not a widespread phenomenon in the Gulf of Mexico.
Application of the API Compendium To Examine Potential Emission Reduction Opportunities for Upstream Operations
Authors: Ritter Karin , Nordrum Susann , Shires Theresa
Published: December 2007

In response to continued interest by its member companies about consistency in greenhouse gas (GHG) emissions estimation, the American Petroleum Institute (API) developed a Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Gas Industry [1]. Initially distributed in June 2001, the Compendium is a result of more than a year long effort by API to screen, evaluate and document a range of calculation techniques and emission factors that could be useful for developing GHG emissions inventories.

In a continued effort to enhance the real-world application of the Compendium, API is examining the applicability of the Compendium methodologies to assess emission reductions from specific projects. This paper presents findings from this follow-on activity. Although the reduction activities presented may not be applicable to all locations, and the estimated emission reductions may not be achievable for all situations, the purpose of this study is to illustrate use of the Compendium and identify potential methodological issues. This paper examines technical considerations associated with estimating pre- and post-project emissions for a variety of emission reduction scenarios.
Discharge of Produced Water: New Challenges in Europe
Authors: Garland Emmanuel , Hjelde Erik
Published: December 2007

At present time, North Sea is the main offshore exploration and production (E&P) area in Europe. Due to ageing of the fields, produced water (PW) has now become the prime source of oily discharge to the marine environment from E&P activities.

So far, measures taken to regulate these discharges, at regional or national level, have focused chiefly on "dispersed" hydrocarbons. Although there is little evidence, if any, of harmful effect from PW actually discharged into the North Sea, when these discharges met the performance standard set up and are treated according to Best Available Technologies (BAT) as defined in 1992 by the Convention for the Protection of the North-East Atlantic (OSPAR), the pressure made by stakeholders has recently led regulators to take tougher measures regarding the "dispersed" hydrocarbons and to embark on the definition of additional, new prescriptive measures directed at other contaminants, such as chemicals used offshore and aromatic compounds.

During the last decade, tremendous research efforts have been made by the industry to design more efficient treatment facilities. As a result the 90's can be considered as the hydrocyclones decade, while the 2000's will see a wider range of techniques used, and the implementation of more preventive measures for reducing the overall load such as re-injection of PW or water shut-off techniques.

But the ongoing discussion on performance standards, and the competition for continuous reduction of the content of contaminants in PW at whatever the cost can be – even when it represents only a small percentage of the total input of contaminants in the North Sea – conceals two key questions: how clean is clean? How to set up the balance between additional measures, taking into account their cost, their efficiency, and the inevitable drawback of their additional impact on other compartments of the environment (CO2 emissions, energy and non-renewable resources consumption)?

To answer these two questions, it requires (1) a consensus on how to assess long-term effects of PW discharges and (2) that the issue is examined from a different point of view: the ecosystem, and its sustainability. Extensive research has been undertaken to develop tools for a better understanding and assessment of the long-term effects, while a new approach has recently emerged since the entry into force of Annex V of the OSPAR Convention, which should lead to the definition of Ecological Quality Objectives in the future. But this approach could be hampered by a recent initiative from the European Commission, which could lead to a total ban of produced water discharges by 2020. Notwithstanding, at present time, operators strive to encompass a holistic approach of water management.
Worldwide Drill Cuttings Injection Permitting Requirements and Guidelines
Authors: Guo Quanxin , Abou-Sayed Ahmed S.
Published: December 2007

Cuttings and other drilling waste injection through downhole fracturing started in the late 1980s and by the early 1990s, drill cuttings injection was being performed worldwide as an economically sound and environmentally safe long-term solution for drilling and production waste management. Although drill cuttings injection has become the preferred drilling waste management option in many parts of the world, each situation is different and the biggest hurdle in applying this technology for drilling and production waste management in some countries is waste injection permit application either because the regulatory agencies have not established any permitting requirements and application procedures or because the E&P operators are not familiar with the application process. Although different regions or countries have different permitting requirements, many of the requirements are essentially the same. This paper presents a review and analysis of worldwide drilling waste injection permitting requirements. Common permitting requirements are given with application procedure guidelines. The operators can use the guidelines to prepare their permitting application, while the regulatory agencies may use the review and guidelines as a reference for establishing or streamlining their own drill cuttings injection permit application requirements and procedures.
New Hydraulic Fracturing Fluid Technology Reduces Impact On The Environment Through Recovery And Reuse
Authors: Parker M. , Slabaugh B. , Walters H. , Weaver J. , Hanes R.
Published: December 2007

Hydraulic fracturing fluid systems are used to create the required fracture geometry and transport proppant into the fracture with a distribution that allows for the optimum performance of the well. Most systems currently use water-soluble polymers composed of guar or guar derivatives. Additional materials are used to optimize the fluid characteristics for the application and also to degrade the water-soluble polymer to make it easier to recover from the well prior to production. The recovered, degraded fluids cannot be used again and must be disposed of in a proper manner.

A new hydraulic fracturing fluid system has been developed that provides excellent performance during the fracturing process with post-fracture treatment fluid recovery approaching 100%. This fluid has the added benefit of being reusable after it is recovered following the treatment and prior to production. The benefits of reuse include the cost savings associated with capturing and reusing chemicals, the cost savings because of reduced water volume requirements for subsequent treatments, and the elimination of disposal costs. In addition, the total volume of chemicals required for fracturing operations is significantly less, thus reducing the demand on our environment.

Field analyses of the returned fluid determine parameters of maintenance and reconstitution for use in subsequent fracturing. This paper will outline the application of this fluid system, the concept for recycling and reuse, and the procedures necessary to properly use the recovered fluid in subsequent treatments.
Integrated Waste Management: Successful Implementations of Thermal Phase Separation Technology for Oil- and Synthetic-Based Cuttings and Drilling Fluid Waste
Authors: Antle Glenn , Gover P. , Pruett J. O.
Published: December 2007

Environmental legislation governing the disposal of drilling waste is continually restricting the discharge limits of drilling fluids and drill cuttings. Operators are charged with achieving a balance between minimizing the potential environmental impact of the drilling fluid while maintaining wellbore stability. Many reservoirs by their inherent nature, as well as the performance advantages of oil-based and synthetic-based drilling fluids, often preclude the use of a water-based fluid. The resultant oleaginous-based drilling fluid and cuttings, whether they are synthetic or diesel, present a complex and costly waste management challenge.

During the planning stages of a drilling project it is important to create an Integrated Waste Management Plan (IWMP). The IWMP takes into account the various types of waste generated by Exploration and Production (E&P) operations in a given area. The key feature of an IWMP is resource management. The use of thermal desorption technology as part of an IWMP allows the recovery and reuse of valuable liquids from the drilling waste. These recovered fluids can be reused as base fluid for reconditioning or building new drilling mud, or as a fuel source.

Spent materials from drilling, completion and workover operations represent the largest volume of waste typically included in an IWMP. These wastes include drilling fluids and/or cuttings from drilling operations. Due to more stringent environmental regulations with respect to hydrocarbon discharge limits, the use of thermal phase separation (TPS) technology helps operators meet their waste management goals in a cost effective and efficient manner. The economic benefit to the operator using TPS technology is greatly enhanced by the value and cost savings associated with the reuse of the recovered fluids.

Operator A selected TPS technology to provide drilling waste management and fluid recovery for a field development project in Blocks 10 and 12 in Ecuador. Operator B selected TPS technology for the Tengiz reservoir in Kazakhstan. TPS is a technology that recovers water, oil and other base fluids that would otherwise be transported for disposal. This paper describes the IWMP approach to the planning, designing and implementation of thermal treatment for these two distinct drilling operations in Ecuador and Kazakhstan. This paper will show how the synergistic approach to waste management enabled both operations to meet all environmental and operational objectives in terms of handling and disposing of drilling waste.

The IWMP approach has proven cost effective on many drilling projects around the world. The authors will chronicle the use of thermal treatment as part of successful waste management plans on drilling projects in an eco-sensitive area of Ecuador and in Tengiz, Kazakhstan. Similar projects are under consideration for Mexico, South America, Russia, and sites in the United States.
Manual Tubing Rotation Reduces Rod Pumping Failures by 76%
Authors: Hart Philip E.
Published: December 2007

A large Illinois oil field implemented the use of a new low cost manual tubing rotator in 25 marginal oil wells to reduce wear failures. Wear failures were indicated by "tubing splits" (Mechanical Wear1) or "corrosion occurring along a straight line due to corrosion inhibitor being wiped off from wear (Corrosion Due to Wear)". The failure rate was lowered from 203 repairs/year to 49 repairs/year (a 76% reduction) for "all failure mechanisms". Failures due to "Mechanical Wear or Corrosion Wear" were reduced from 108 repairs/year to 18 repairs/year (an 83% reduction). This success yielded over a 100% rate of return since the tubing rotator will normally pay out after eliminating the first pulling job and requires only 15 minutes per year of extra labor. Economics suggest that 100% to 20% investment rate of returns are achievable in wells failing once every 24 months or more often (not considering downtime losses). Thus, the manual rotator is not just for "problem" wells and significantly reduces wear failures.
Optimization of Acid Fracturing to Improve Heavy Oil Production in Naturally Fractured Carbonates
Authors: Wang Xugang , Zou Honglan , Zheng Xingquan , Zhang Fuxiang , Fan Yonghong , Cheng Xingsheng , Zhang Rusheng
Published: December 2007

This paper presents detail experimental and theoretical study and the results of successful applications of acid fracturing to enhance heavy oil recovery in Ordovician formation in LN region of TARIM, China. The Ordovician formation in LN field is extreme heterogeneous carbonate with naturally fractures. The reservoir temperature is 140 °C, and the formation fluid has API gravity of 8.

To optimize the acid system for this complicated formation condition, we first studied the reaction characteristic of gelled acid compared with straight acids at temperature ranging from 60°C to 140°C. Acid conductivity experiments were conducted with a unique conductivity instrument using limestone samples designed to simulate alternating stages of pad acid fracs and closed acidizing process. The original way to determine acid/rock reaction rate at high temperature is to extrapolate from low temperature test data. Our test has shown that the actual reaction rate at high temperature is much less than that obtained from the low-temperature data. Also, results show that gelled acid is 2.5 times more retarded than straight acid and the delayed nature of gelled acids is useful forgenerating longer etched fractures. Gelled acids also have higher viscosity than straight acid, which reduces fluid loss and friction pressure in acid fracturing applications.

Based on the experimental result, some novel approaches were used to evaluate stimulation and improve heavy oil production. FMI logging technique was used pre-and post-stimulation, which shows that fracture numbers and shapes were much different from theoretical reorganization. Three kinds of fractures were observed, including vertical fractures, horizontal fractures and inclined fractures. A theoretical model considering wormholing was used to evaluate pressure decline after acid fracturing. In order to minimize post-stimulation production decline rate in field, a new technique, mixing light oil with heavy oil at bottomhole condition, was introduced into this area to significantly improved oil mobility.

Field cases of applying the new approach of acid fracturing in the Ordovician formation in TARIM over five years are presented. The field cases show the improvements in production of heavy oil resulting from the comprehensive approach.
Cost-Effective Treatment Programs for Paraffin Control
Authors: Barker K. M. , Waugh K. L. , Newberry M. E.
Published: December 2007

Paraffin related problems of deposition, congealing oil and interface/tank bottoms cost the gas and oil industry hundreds of millions of dollars each year. Most of this money is spent without a clear understanding of the problems being experienced or their cost. If the real cost of a problem is not calculated before a treatment program is started it may not be possible to know if that program is cost effective. This paper will attempt to explain the difference between an inexpensive program and a cost effective program. Case histories will be presented.