bluuebunny/crossref_metadata_2025 huggingface dataset:
Use of Drilled-in Casing in Slim Deepwater Exploration Wells
Authors: Leach Colin , Bamford Tony
Published: December 2007

A new type of seabed support system is being developed that incorporates a subsea shut-off system and surface BOP. This enables slim, "finder wells" to be established in deepwater with drilled-in casing. By minimising the loads that must be supported by the vessel, the operator has a much greater choice of vessels for a given water depth. The system as described is aimed at "simple" deepwater wells, such as those found in West Africa – the impact of the approach described in this paper is to reduce exploration well costs by more than 50% when compared to the cost of deploying a "conventional" approach.

With this system, a 7 5/8" casing string is drilled into place (becoming the first pressure containing barrier) and converted into a riser. This is all done on a single trip to speed up the operation and reduce the risk. The casing string is captured and sealed within the subsea shut-off system, only after installing and spacing out a surface BOP. This approach has many advantages.

A surface BOP is used for primary well control, but in the event an emergency disconnection is required, dual shear rams cut the 7-5/8" casing and seal in the well. The system then allows a conventional subsea reconnection of the riser (casing).

This paper describes:

the basis for the design of the system, the engineering work carried out to validate the design, particularly with respect to the soil stability, bending loads and riser analysis. extending the water depth capability of the control system. Improving the reliability of the pipe shearing system A description of other key components of this new drilling system is included. It is intended to utilize composite coil tubing to perform the drilling below the 7 5/8" casing, though conventional slim jointed pipe could be used.
Drilling Fluids Planning and Execution for a World Record Water Depth Well
Authors: Dieffenbaugher J. , Dupre R. , Authement G. , Mullen G. , Gonzalez Y. , Tanche-Larsen P. B.
Published: December 2007

Proper drilling fluids planning and execution play a major role in minimizing the likelihood of drilling difficulties such as those encountered in ultra-deep waters.

Deepwater drilling is inherently expensive. Because of this, the proper selection of drilling fluids and other support technologies requires careful evaluation to diminish commonly observed deepwater challenges. These challenges include hydrate suppression, shallow water flows, logistics, lost circulation mitigation, viscosity profiles. Another critical deepwater challenge is properly managing ECD to maintain optimal well site safety and environmental compliance.

This paper discusses the planning and execution of a drilling fluids program for a world record ultra-deepwater well. The well was located at a water depth of 10,011 ft. (3,051 m) in the Gulf of Mexico's Alaminos Canyon (Block 951). The well was drilled to TD (22,695 ft. [6,917 m]) using an advanced synthetic-based mud that met all Gulf of Mexico compliance requirements and advanced engineering software and tools.
Application of Real-Time Wellbore Stability Monitoring on a Deepwater ERD Well
Authors: Greenwood J. A. , Brehm A. , van Oort E. , Algu D. R. , Volokitin Y. E.
Published: December 2007

Good geomechanical modeling can provide valuable information for the efficient design and drilling of wellbores. Incorporating real-time wellbore stability monitoring during drilling can reduce the associated risks, especially for deepwater extended-reach wells. This paper presents the preparation, delivery, and outcome of the field trial for a real-time wellbore stability monitoring service delivered at Shell Exploration and Production Company's office in New Orleans.

Three key objectives were set for the field trial: (1) to develop the processes to incorporate real-time wellbore stability into the current operations center monitoring provision, (2) to provide frequent updates of the wellbore stability model using a geomechanical modeling technique that was independent of the operator's own methods, and (3) to monitor and verify the geomechanical model based upon the drilling experience enabling proactive decision making during drilling. For the operator's asset team, the main objective was to reduce trouble time and make execution of the well successful.

Ram Powell VK 913 A-9 well was chosen as a candidate for the field trial. The Ram Powell tension-leg platform is located in 3200 feet of water in the Eastern Gulf of Mexico. A-9 was planned as an extended-reach exploration and would have the highest angle at the shallowest depth in the field. A geomechanical model for the prospect had already been created using the operator's own well-established methodology. This pre-drill model was transferred into the service company's software, and the real-time model was calibrated to generate as close to the same output as possible. After verifying the real-time model using the drilling experience on the closest offset wells, the 24 hr real-time stability monitoring commenced. The real-time geomechanical monitoring encompassed pore pressure prediction, rock property calculations from formation evaluation tools, wellbore trajectory updates, and the use of surface and downhole drilling data to verify the geomechanical model.

Integration of the real-time wellbore stability monitoring contributed to the successful drilling and casing of this deepwater extended-reach well. The trial resulted in a greater understanding of the geomechanics of the field. The trial also resulted in a better understanding of procedures for maximizing the value of real-time data and of associated monitoring services, services that will be incorporated in future Shell E&P wells.
DDV Reduces Time to Round-Trip Drillstring by Three Days, Saving £400,000
Authors: Sutherland Iain , Grayson Brian
Published: December 2007

Fluid invasion of a reservoir during conventional overbalanced drilling operations can cause considerable formation damage. Increased awareness of the degree of damage possible has raised interest in the benefits that underbalanced drilling (UBD) offers. UBD techniques are not necessarily suitable for all reservoirs but can provide significant benefits in certain instances.

During UBD operations, the formation is allowed to flow; so a surface pressure is ever present in the annulus. A rotating control head is used to control the pressure. As tripping begins and the pipe is stripped through the wellhead, the pressure must be managed to prevent a pipe-light situation.

Killing the well to control it and allow for conventional tripping of drillstring is not always a viable solution; and, until recently, the only accepted method for tripping drillstring in a constant underbalanced state has been snubbing, which can have operational and economic drawbacks in some situations. This paper describes how implementation of the downhole deployment valve (DDV) in a Southern North Sea drilling program reduced overall program costs, set multiple records, and demonstrated successful integration of a new technology into one of the most critical underbalanced operations in the world.
Mooring and Riser Management In Ultra-Deep Water and Beyond
Authors: Pelley Darrel K. , Steddum Riddle E. , Westlake Andrew S.
Published: December 2007

In recent years, offshore oil and gas exploration has rapidly advanced to record water depths that were beyond conception 20 years ago, with the 10,000-ft water depth barrier hurdled in 2003 in the US Gulf of Mexico. Drilling equipment design and capability to achieve this record has simply grown to meet increased capacity requirements.

This paper outlines the mooring and drilling riser management challenges that will need to be realized in 10,000 feet of water and beyond. By defining the boundary conditions for moored and dynamically-positioned scenarios in future record water depths, the challenges to the design and operation of mooring and riser systems can be explored, including component design issues, deployment techniques and system management in adverse environmental conditions. Previous work undertaken on this subject by Transocean shows that the capabilities used to break the 10,000-ft barrier will require yet another step-change to drill in water depths of 12,000-ft (DP) or 10,000-ft (Moored) with conventional subsea well control equipment and marine drilling risers.

Two scenarios are presented, one each for moored and dynamically positioned vessels to demonstrate the requirements that require special consideration for successful operation and management of mooring and marine drilling risers.
Reducing Risk and Cost in Diverse Well Construction Applications: Eccentric Device Drills Concentric Hole and Offers a Viable Alternative to Underreamers
Authors: Rasheed Wajid , Trujillo Jorge , van Oel Ruben , Anderson Mark , McDonald Scott , Shale Les
Published: December 2007

Increasingly, operators seek to underream. Whether driven by cementing tolerances, ECD improvements, pore pressure fracture gradients, production increases, swelling shales/salts or setting sand screens, underreaming is sought after at all stages of field development.

To date, the industry has a common perception that concentricity can only be delivered through concentric cutting mechanisms. This paper proves otherwise. The performance, risks and suitability of an eccentric underreaming device are compared with concentric underreamers. Usage in over 100 well sections is tabulated and reviewed to verify the device drills concentric hole in differing formations and applications.

Pilot bit and underreamer cutter characteristics are matched for directional control, durability and hole quality. Specific attention is paid to N Sea & GOM run history covering usage with push and point-the-bit rotary steerables. In exploratory, deepwater or complex well paths, the device is placed above a 3-D rotary steerable and full logging suite. Here the problem of leaving pilot gauge rathole is also addressed. In enhanced RPM, motor directional applications it is placed as nearbit.

Computational fluid dynamics, nozzle and PDC cutter layouts are also discussed with regard to optimizing cuttings evacuation, hole cleaning, BHA stability and ROP.

In conclusion, 20 different well construction activities are presented and used as a benchmark for the evaluation of the risks and suitability of the device as compared with concentric underreamers.
Mature Field Benefits from Application of High-End Technology
Authors: Bone Glenn , Janwadkar Sandeep , John Wolfgang , Isbell Matt
Published: December 2007

Economical development of deep oil and gas wells in the Marlow field in Southern Oklahoma requires efficiently drilling a complex geological structure with faulted and highly dipping formations. Operators typically employ conventional motor directional systems to keep inclination to a minimum in the 8-3/4" vertical hole section. While this type of bottom hole assembly (BHA) has improved directional control, it still leads to unacceptable angle building tendencies/dogleg severity and poor vertical hole quality resulting in additional directional issues in subsequent hole sections. In addition, the conventional directional assembly increases well costs due to multiple deviation correction runs with different BHA configurations resulting in more flat time, lower cumulative bit penetration rate, and more bits/runs per section.

To address these issues, the service company studied drilling performance, mud logs and wireline data from offset wells. The resulting analysis detailed the key problems and led the operator to set new objectives for the 8-3/4" vertical hole section of achieving the highest possible rate of penetration (ROP) while maintaining a near-vertical wellbore. An implementation strategy was outlined that had two main components including a sophisticated vertical drilling system (VDS) with a new polycrystalline diamond compact (PDC) bit technology.

This approach has been utilized to drill the 8-3/4" hole section on two wells with the following results: Reduced inclination from 22º to 1.5º (VDS) and reduced dogleg severity (DLS) from 4º/100ft to just 1º/100ft (VDS). The new system has also reduced torque/drag and delivered a smooth quality wellbore and totally eliminated costly correction runs. The increased wellbore quality has allowed the operator to log, then set 5 ½" casing without incident. The operator has experienced increased performance when kicking off below a section drilled with the new BHA (VDS/bit) improving directional control and aiding geosteering to the target reservoir.
Bromine-Based Biocides for Effective Microbiological Control in the Oil Field
Authors: Carpenter J. F. , Nalepa C. J.
Published: December 2007

Maintaining biological control of oilfield systems is critical. Microorganisms can cause well souring, equipment plugging, loss of formation injectivity, destruction of essential additives, and MIC (microbially induced corrosion). To minimize these problems, biocides are often used. Systems commonly treated with biocides include water injection, fracturing fluids, and hydrostatic test waters.

In this paper we review the family of bromine-based biocides and discuss the basics of their chemistries and properties. We focus on a new stabilized bromine chloridebased biocide that has been demonstrated in a slickwater fracturing fluid field trial. Here, excellent microbiological control was maintained cost-effectively with relatively low biocide residuals.
A Chemical "Trigger" Useful for Oilfield Applications
Authors: Todd B. , Funkhouser G. P. , Frost K.
Published: December 2007

A number of oilfield operations are controlled by use of delayed chemical reactions. Breakers for fracturing and gravel packing fluids, filter-cake cleanup treatments in horizontal wellbores, and retarded acidizing are just a few examples. However, these reactions are best described as slow or gradual reactions and not truly delayed chemical reactions. The gradual degradation of a fracturing-fluid viscosity or a drill-in fluid filter cake can take place over a matter of hours. But even greater benefit could be realized in completion operations if events could be delayed for days and triggered at the desired time.

The delayed acid-releasing system, which is based on orthoesters in combination with alkaline inhibitors, can remain seemingly inactive for days before becoming strongly activated. The acid that is generated can then be used to break polymers, remove filter cakes, or activate other chemical processes.

The paper describes the chemical principle on which the system is based, and discusses a number of applications that could be improved and economized with the long-term delay and scheduling flexibility offered by the chemical-trigger system.

Also presented are the current operating envelope and plans for future widening of the temperature and delay-time ranges. A number of new testing procedures used to prove the system's unique properties are reviewed in the paper.
Efficient History Matching Using a Multiscale Technique
Authors: Aanonsen S. I.
Published: December 2007

It is demonstrated that a method for multiscale history-matching can be used to improve efficiency and/or quality of the solution when achieving a fine-scale match as compared to history-matching directly on the fine scale. Starting from a given fine-scale realization, coarser models are generated using a global upscaling technique where the coarse models are "history-matched" with respect to the solution at the fine scale. Conditioning to dynamic data is done by history-matching a coarse model, and this model is then successively refined using a combination of downscaling and history matching until a model matching dynamic data is obtained at the finest scale. The advantage of this procedure is that the large-scale corrections are obtained using fast models, which combined with proper downscaling procedures provide a better initial model for the final adjustment on the fine scale. The coarse-scale history-matching also provides a regularization of the fine-scale match making the process less dependent on a correct prior model. With the proposed methodology, a series of models of different degree of complexity, all being consistent with both static and dynamic data, may be generated without additional cost. Effects of using á priori information and different initial downscaling techniques, such as sampling or block kriging with sequential Gaussian simulation are investigated using 2 synthetic reservoir models.
"Surface BOP, Slim Rise or Conventional 21-Inch Riser – What is the Best Concept to Use"
Authors: Childers Mark
Published: December 2007

There are four (4) ultra deepwater (over 5,000 ft) subsea drilling systems available to the industry. The Conventional 21-inch riser/18 ¾ inch BOP stack used with 5th Generation MODUs, Surface BOP (SBOP) located directly under the rotary with high pressure casing riser to the seafloor using a 2nd to 5th Generation Semi MODU, a version of the SBOP with a Subsea Disconnect System (SDS) at the seafloor, and the Slim Riser Concept using a 16-inch standard riser with a 3rd or 4th Generation Semi MODU and 18 ¾ inch BOP. The SBOP with the SDS consists of two hydraulic connectors and two shear rams. Slim hole technology is an integral part of SBOP and Slim Riser concepts.

The SBOP concept is most economical and successful when a large number of wells (15 or more) are drilled such to payout the CAPEX for MODU modifications and other equipment. In addition, the wells should be expendable, normal pressure, less than 3 strings of casing below the BOP, slim hole drilling technology is acceptable, and used in a benign environment5. If the latter requirements are present and shallow gas or well control is an issue and/or the location is not in a benign environment, then the SBOP with a SDS is worth considering. The Slim Riser Concept is best for wells that are to be kept for production or reentry, are more complicated and require more time and technology to drill, are in more severe environments, disconnection of the riser is more likely, there are a reasonable number of wells (9 to 12 months of contract work) for payout of the MODU modifications and equipment, and/or the Operator is not comfortable with the SBOP concepts. Cost to do the modifications to the MODU, schedule (rig and well), well type and anticipated problems, operator and regulator acceptance of a concept, and rig type availability are among major factors in selecting a concept. The primary incentive for using the SBOP without SDS and/or the Slim Riser Concept is the ability to use a much lower price MODU day rate vs. the Conventional 21-inch concept. The pros and cons, advantages and disadvantages, and other factors in relationship to the 4 concepts mean that one concept is not the "best" solution for every well program. Rigorous analysis and evaluation of all factors are key in selecting the "best" concept for the well (s) or project under consideration such to derive the most cost effective and low risk approach.
"Clean Up" of Oil Zones after a Gel Treatment
Authors: Seright R. S.
Published: December 2007

Because polymers and gels can reduce permeability to water much more than that to oil, an unfavorable displacement (high mobility ratio) usually occurs in oil zones when wells are returned to production after bull-headed gel treatments. Since oil displacement through gel is unfavorable, the permeability to oil requires a large throughput to stabilize. Consequently, oil zones often exhibit a significant "cleanup time" after field applications of gel treatments. The oil and water throughput requirements for stabilization of permeabilities were studied for a relatively "strong" pore-filling Cr(III)-acetate-HPAM gel and for a "weak" adsorbing polymer. As oil throughput increased from 1 to 100 PV, permeability to oil gradually increased by factors from 5 to 10 for cores treated with the Cr(III)-acetate-HPAM gel and from 2 to 3 for cores treated with the adsorbing polymer. In contrast, after treatment with gel, permeability to water stabilized rapidly and remained very low for over six months. An explanation is provided.

A simple mobility-ratio model was used to predict cleanup times for both fractured and unfractured wells after a gel treatment. The time to restore productivity to a gel-treated oil zone (1) was similar for radial versus linear flow, (2) varied with the cube of distance of gel penetration, (3) varied inversely with pressure drawdown, (4) varied inversely with the kw at Sor in the gel-treated region, and (5) was not sensitive to the final ko at Swr. Although ko at Swr (after gel placement) had no effect on the cleanup time, it strongly affected how much of the original oil productivity was ultimately regained. Earlier work demonstrated that an acceptable gel or polymer placement can be achieved by unrestricted injection of gelants during linear flow (e.g., vertically fractured wells). However, in radial flow through matrix (e.g., unfractured wells), hydrocarbon productive zones must be protected during gelant or polymer placement. These conclusions were confirmed by our new results for both the Cr(III)-acetate-HPAM gel and the adsorbing polymer.
Modeling of the Asphaltene Precipitation in Bangestan Reservoir of Kupal Field
Authors: Jamshidnezhad M.
Published: December 2007

Modeling of asphaltene precipitation in Bangestan reservoir of Kupal field in southwest of Iran is the purpose of this study. The modeling technique based on the representation of the precipitated asphaltene as a pure dense phase and division of the heaviest component in the oil into non-precipitating and precipitating components. A set of dummy experimental data was used to tune an equation of state based model that represents the asphaltene as pure component solid. Results of the work show that the chosen model could accurately represent the behavior of the fluids of this reservoir.

Experiences in NISOC fields prove that when solid precipitation is about 10 % (w/w), the problem of asphaltene will serious. Based on this study, we concluded that at about 5300 psia the amount of solid is 10 %. Therefore, when pressure in the Bangestan reservoir of Kupal field approach to this critical pressure (5300 psia) gas should be injected. Now, NISOC reservoir-engineering department are providing a plan for gas injection in order to increasing pressure in this reservoir.

The Bangestan reservoir of Kupal field started producing in 1989 under primary depletion. The reservoir has undersaturated oil with the production mechanisms being fluid and rock expansion along with gravity drainage.
Development of Green Chemicals For Cleaning Operations in Platforms Decommissioning
Authors: Dalmazzone C. , Carrausse M. , Tabacchi G. , Mouret A. , Noïk C.
Published: December 2007

Proposal

Chemicals in decommissioning activities are not considered as an important challenge as far as all the products used are selected from the PLONOR list. Consequently, an important work has to be done to obtain safe and efficient products to facilitate cleaning operations and to limit the volumes of polluted water. The main constraint is to propose detergent formulations that are non-toxic and biodegradable. Furthermore, formulations must be compatible with cold seawater and must allow a fast separation of hydrocarbons from the aqueous phase. The objective of this paper is to present the development of a strict methodology for cleaning products selection. The innovative aspect of this methodology is firstly based on a pre-selection of safe molecules coming from a green chemistry, such as alkylpolyglycosides for instance. In a second step, formulations based on mixtures of several efficient and safe active matters are tested on different supports (glass, steel, cement…) in order to assess their detergent efficiency against several types of crude oils and weathered crude oils, the kinetics of separation of the formed emulsion, the formation of foam and the quality of the separated aqueous phase. Ecotoxicity tests on molecules are performed according to OSPARCOM guidelines (aquatic toxicity, biodegradation, and bioaccumulation). Complementary toxicity tests are also carried out on the separated water after cleaning, in order to estimate the toxicity of the aqueous phase to be discharged. The last phase of the methodology consists in a validation of formulations performances in large scale experiments performed in CEDRE (Center of Documentation, Research and Experimentations on accidental water pollutions, France), on a specific clean-up device that simulates typical operations of cleaning under pressure. The main objective is to develop green formulations for cleaning oil polluted surfaces through a rigorous methodology based on technical and environmental criteria.
Novel Multiple Resolutions Design of Experiment/Response Surface Methodology for Uncertainty Analysis of Reservoir Simulation Forecasts
Authors: Li B. , Friedmann F.
Published: December 2007

Response surfaces (RS) are useful and simple proxies to simulators, which relate in a closed form output variables (oil recovery factor, oil rate, etc.) of a simulator to input parameters over the entire parameter space. These proxies can then be used to compute production forecast uncertainty profiles with Monte Carlo calculation, instead of relying on time consuming reservoir simulation.

Typically, design of experiment (DOE) and response surface methodologies (RSM) are used to both identify statistically significant factors and to generate RS. RS are usually low order polynomials, which are generated by using the regression method. These methodologies work well if response surfaces are smooth with weak non-linearity. However, when these polynomials fail to meet reasonable accuracy criteria, adding more points to the design will only marginally improve RS accuracy. Response surface methodology can be adapted for such cases by using interpolation methods (Kriging, Spline, etc.) instead of regression method. But, most interpolation methods tend to smooth out non-linearity. These interpolated proxies can become substantially inaccurate, if: Non-linear effects are very strong;The non-linearity is not uniformly distributed throughout the parameter space.

In this paper, we introduce a novel RSM and its supporting DOE methodology to construct response surfaces as proxies of a simulator when input factors of the simulator such as faults cause strong non-linear effects. These methodologies are used to generate RS of arbitrary shapes by iteratively interpolating on a multilevel grid in the experimental space, which allows the local subdivision of the parameter domain. New partitions and interpolation points are added adaptively in the selected parameters regions, if local errors of the constructed response surface exceed a pre-selected threshold. The art of these methodologies consists in: Splitting the whole domain into sub-domains of multiple scale levels, where the components of a RS can be accurately modeled with ‘thin plate’ spline interpolants. The resultant RS is obtained by combining its global and local components.Achieving adequate RS accuracy with the minimum number of simulation runs.

We modify the SPE9 Benchmark problem to investigate the method's validity and efficiency. We compare it with traditional DOE and RSM methodologies. Finally, we perform Monte Carlo simulation using the RS proxies to assess uncertainty of the production forecasts. Results show that the presented methodologies work accurately and efficiently for problems with strongly non-linear effects, especially when the non-linear effects are non-uniformly distributed.
Implementation of Adjoint Solution for Optimal Control of Smart Wells
Authors: Sarma P. , Aziz K. , Durlofsky L. J.
Published: December 2007

Practical production optimization problems typically involve large, highly complex reservoir models, thousands of unknowns and many nonlinear constraints, which makes the numerical calculation of gradients for the optimization process impractical. This work explores a new algorithm for production optimization using optimal control theory. The approach is to use the underlying simulator as the forward model and its adjoint for the calculation of gradients. Direct coding of the adjoint model is, however, complex and time consuming, and the code is dependent on the forward model in the sense that it must be updated whenever the forward model is modified.

We investigate an adjoint procedure that avoids these limitations. For a fully implicit forward model and specific forms of the cost function and nonlinear constraints, all information necessary for the adjoint run is calculated and stored during the forward run itself. The adjoint run then requires only the appropriate assembling of this information to calculate the gradients. This makes the adjoint code essentially independent of the forward model and also leads to enhanced efficiency, as no calculations are repeated. Further, we present an efficient approach for handling nonlinear constraints that also allows us to readily apply commercial constrained optimization packages. The forward model used in this work is the General Purpose Research Simulator (GPRS), a highly flexible compositional/black oil research simulator developed at Stanford University.

Through two examples, we demonstrate that the linkage proposed here provides a practical strategy for optimal control within a general-purpose reservoir simulator. These examples illustrate production optimization with conventional wells as well as with smart wells, in which well segments can be controlled individually.
Effect of Grid Deviation on Flow Solutions
Authors: Wu X. H. , Parashkevov R. R.
Published: December 2007

The two-point flux, finite volume method (FVM-2P) is the most widely used method for solving the flow equation in reservoir simulations. For FVM-2P to be consistent, the simulation grid needs to be orthogonal (or K-orthogonal if the permeability field is anisotropic). It is well known that cornerpoint grids can introduce large errors in the flow solutions due to the lack of orthogonality in general. Multi-point flux formulations that do not rely on grid orthogonality have been proposed, but these methods add significant computational cost to solving the flow equation.

Recently, 2.5D unstructured grids that combine 2D Voronoi areal grids with vertical projections along deviated coordinate lines have become an attractive alternative to corner point gridding. The Voronoi grid helps to maintain orthogonality areally and can mitigate grid orientation effects. However, experience with these grids is limited.

In this paper, we present an analytical and numerical study of these 2.5D unstructured grids. We focus on the effect of grid deviation on flow solutions in homogeneous but anisotropic permeability fields. In particular, we consider the grid deviation that results from gridding to sloping faults. We show that FVM-2P does not converge to the correct solution as grid refines. We further quantify the errors for some simple flow scenarios using a technique that combines numerical analysis and asymptotic expansions. Analytical error estimates are obtained. We find that the errors are highly flow dependent and they can be global with no strong correlation with local non-orthogonality measures. Numerical tests are presented to confirm the analytical findings and to show the applicability of our conclusions to more general flow scenarios.
Spatial Error and Convergence in Streamline Simulation
Authors: Jimenez E. , Sabir K. , Datta-Gupta A. , King M. J.
Published: December 2007

Streamline models are routinely used for waterflood optimization and management, and are being extended to more complex processes, e.g., compositional simulation. Despite these new developments, no systematic study has examined the underlying numerical spatial and temporal discretization errors in streamline simulation and their convergence. Such studies are a prerequisite to determining the optimal density of streamlines during simulation and ensuring the resulting accuracy of the solution.

In this paper we first examine transverse spatial errors, e.g., errors due to the number or placement of streamlines. We provide an analytic proof and a numeric demonstration of the order of spatial convergence of the mass balance discretization error. Both global and local calculations are performed, and demonstrate the impact of stagnation regions on the order of convergence. A second transverse error arises for faulted grids, where lack of flux continuity at cell faces can lead to incorrect trajectories. These trajectory errors are of zeroth order, and can only be resolved by introducing additional degrees of freedom into the streamline velocity model. Longitudinal spatial errors also arise, and are associated with the inaccurate calculation of time of flight across cells.

We show that the commonly used algorithm for corner point cells leads to inaccurate time of flight calculations for stratigraphic grids, depending upon aspect ratio. We provide a simple and exact means of calculating the time of flight for arbitrary corner point cells, or unstructured grids, in two or three dimensions, for either compressible or incompressible flow. Finally, using this new time of flight formulation, we analyze a series of cross-sectional finite difference simulations to identify grid orientation errors in the numerical calculation of flux and spatial error.
Optimizing Wellbore Design Using Solid Expandable Tubular and Bi-Center Bit Technologies
Authors: Morrison W. , Baggal Z. , Baxendale B. , Boudreaux R.
Published: December 2007

Throughout the oil and gas industry a need exists to reduce hole size and subsequent casing strings to reach the pay zone in a safe manner with appropriate zonal isolation of the various formations. Benefits in achieving such well design can be economically advantageous to the operator.

In certain fields of Saudi Arabia, a relatively thin gas cap exists at the top of the Arab-D oil-producing zone. Isolating this gas cap is necessary to prevent future production from the gap.

In wells where a gas cap is expected, 300 to 400 ft of high angle 8-1/2 in. hole is drilled and cased off with a 7 in. liner. A 6-1/8 in. production hole is then drilled horizontally to total depth (TD).
Experimental and Numerical Studies of Gas/Oil Multicontact Miscible Displacements in Homogeneous Porous Media
Authors: Al-Wahaibi Y. M. , Muggeridge A. H. , Grattoni C. A.
Published: December 2007

Both vaporizing and condensing miscible gas floods are being conducted in a large number of reservoirs worldwide. The performance of these gas floods is usually determined via a combination of laboratory analysis and compositional simulation. However the ability of numerical simulation to correctly predict the progress of a multi-contact miscible displacement has not been fully verified

This paper investigates the physical processes occurring during multi-contact miscible displacementthe ability of the Coats correlation to model the changes in gas-oil relative permeabilities with interfacial tension (IFT) and the associated inaccuracies in predicted oil recoverythe importance of gas/oil disequilibrium on the prediction of oil recovery and gas-oil ratio

These objectives are achieved by using a commercial compositional simulator to predict the behaviour of multicontact miscible (MCM) floods in well-characterised, bead-pack experiments. Both condensing and vaporizing drives are investigated using a ternary liquid system that exhibits an upper critical point at ambient conditions. Relative permeabilities as a function of IFT were obtained independently from displacement experiments. Glass bead-packs permitted the visualisation of the displacements whilst the effluent profiles in terms of composition and phase volume versus time were measured using a calibration with refractive index of the fluids.

Condensing and vaporizing gas-drive displacements were very efficient with about 90% of the oil in place recovered at one pore volume injected. Compared to immiscible displacements, breakthrough and total recoveries were increased by 8% and 20% respectively. However, in both condensing and vaporising drives, the compositional simulation (that assumes equilibrium conditions) over-predicted oil recovery. Further simulations identified that these errors are due to inaccuracies in Coats’ correlation describing the behaviour of relative permeabilities as miscibility is approached and/or the fact that the produced fluids were not in compositional equilibrium.
A New Technique in Acquiring High Quality Image Logs in Deviated & Horizontal Wells: Case History
Authors: Talabani S. , Efnik M. , Baradi A. , Salim B.
Published: December 2007

Well bore images become increasingly important in identifying formation features and their possible extent.There are two different tools that acquire image data, acoustic and micro-resistivity.Both tools faced difficulties and challenges in acquiring quality data over the deviated and horizontal section of a well.

To perform quality image data in deviated and horizontal section of a well is difficult because of; firstly, drilling rogues, deviated and horizontal section, and these results in poor pad-wall contacts.Therefore, the quality of the resistivity image data is highly affected by the drilling fluid, along with the acoustic data.Secondly, poor mud properties that behaves as a blocking medium to acquire quality data.

A new technique requires modifying in both drilling and mud properties has been applied in different fields with high success.This new technique requires certain bottom hole assembly and drilling parameters, along with drilling fluid properties to better drill smooth holes.

The new technique resulted in smooth horizontal section and better in the deviated section, therefore, better pad-wall contact.Images from both; resitivity and acoustic modes provided high quality data acquisition.As a result, geological features were very clear by the image logs after the implementation of this new technique.

In this paper, the new technique is explained along with case histories from three different fields of the image logs are presented and compared to previous poor quality logs.
Integrated Approach for Improving Development of a Mature Field
Authors: Xiaoguang L. , Xuewen Z. , Sincock B. , Handono B. W. , Mayanullah F.
Published: December 2007

Makmur Field, South Sumatra, Indonesia, is a faulted anticlinal rollover with its major mutli-layer reservoir of distributary mouth bar, delta front sheet, and sub-aqueous channel sand. The field reached its production peak at end of 2001. In order to hold back the bottom or peripheral water encroachment, arrest promptly production declining, and ensure the maximum final recovery, integrated reservoir characterization including detailed microfacies and structure mapping, 3D geostatistic modeling, and subsequent reservoir simulation coupled with routine drainage radius analysis have been conducted. Meanwhile, pressure build-up test and production monitoring were optimized and selected performed.

The effective reservoir management including development infilling, optimized well sidetracking, dual string well completion, gas lifting, active workover operation, as well as drilling of injector and optimization of facility utilization for water injection enhancement has been implemented, which provided a road map for improving the field development. Application of the integrating reservoir management techniques resulted in substantial added reserve and mitigated pressure dropping. The successful infilling and water shut in workover have obviously arresting production declining rate.
Evaluation and Field Applications of Water Treatment Residue as a Profile Control Agent
Authors: Tianjiang H. , Huating Z. , Zongtian L. , Bin Y. , Puchun Z.
Published: December 2007

A great amount of residue from water treatment process in water-flooded oilfields has gradually accumulated and thus caused serious environmental pollution. The water treatment residue is a grey suspension with its density of 1.08g/cm3, and mainly contains over 65% light CaCO3, MgCO3, CaSO4, Fe2S3 and Ca(OH)2, etc. We made laboratory tests, such as microphotograph and the comparison of the core permeability to kerosene, cast model image analysis parameters, mercury injection capillary pressure curve parameters and scanning electron microscope porosity variation before and after profile control. The results indicate that the water treatment residue is of strong profile control and plugging capability, resistance to erosion and long effective period, and thus can be used as a cheap raw material for profile control. In the past 8 years, totally 60164m3 water treatment residue has been used for profile control of 151 wells, with the success ratio of 98% and effectiveness ratio of 83.2%. The field tests show that the starting pressure and injection pressure of the injection wells increased, the apparent injectivity coefficient decreased, the injection profile was obviously improved, and the injection wells achieved long average service life. Thus, more 28381 tons of oil was recovered from the corresponding oil wells, with 3069.55×104 Yuan benefits and a remarkable input output ratio of 1:8.6. The successful application of the water treatment residue as a profile control agent both reduces environmental pollution and converts bane into boon.
Quantification of Asphaltene and Wax Sludge Build-up in Crude Oil Storage Facilities
Authors: Leontaritis K. J.
Published: December 2007

At some thermodynamic conditions, asphaltenes flocculate into larger, almost spherical particles that have a specific gravity of 1.05 to 1.10. Work is cited here that indicates that asphaltene stable colloids exist in oil as very minute particles and that their pre-flocculation sizes are in the range of about 10 to 15 Å This corresponds to 334 and 1,128 molecular weight respectively, assuming asphaltene spherical colloids and an experimentally determined asphaltene density of 1.06 g/cm3. The reason for this high specific gravity of asphaltene particles compared to the rest of the molecules of oils is that they consist mostly of asphaltenes and resins, the heaviest constituents of oils. Roughly, resins have specific gravities of 0.95 to 1.0 and asphaltenes 1.1 to 1.2. Because of their high specific gravity asphaltene particles settle by the force of gravity in storage systems where the convection currents and shear forces are minimal. Some of these particles are large enough to overcome the convection currents and shear forces and settle in large separators and occasionally in large pipes due to Stoke's law effects, especially at elbows changing the direction of flow where the particles impinge against the pipe wall and are temporarily halted.

Wax precipitation often results in the formation of sub-micron wax spherical particles that also settle under the influence of gravity. Although paraffin waxes have specific gravities around 0.8 to 0.85, field waxes have higher specific gravities, usually higher than 0.9, because they usually co-precipitate with asphaltenes and resins, if present. Hence, in oils that contain asphaltenes and resins, precipitating waxes do settle by gravity. It has been shown that asphaltenes and resins are considered responsible for causing the formation of amorphous spherical wax crystal particles rather than wax needle crystals. Both flocculated asphaltene particles and crystallized wax particles agglomerate to form very large micron-level particles whose molecular weights run in the hundreds of thousands or millions. These large particles settle fairly quickly in storage systems.

This paper presents a modeling methodology for the simulation of sedimentation of asphaltene and wax particles in both onshore and offshore storage systems. The asphaltene and wax particle size distribution is usually available from microscopic observations, filtration, and thermodynamic models. The sedimentation calculation is done by assuming that the particles have settled and are at gravimetric equilibrium. Two examples are presented: one 1,000,000-barrel FPSO case and one 250,000-barrel oil storage tank case. Both the FPSO and the tank had lost a substantial fraction of their capacity due to accumulation of asphaltene and wax sludge.
Oilfield Reservoir Souring During Waterflooding: A Case Study with Low Sulphate Concentration in Formation and Injection Waters
Authors: Cavallaro A. N. , Martinez M. E. Gracia , Ostera H. , Panarello H. , Cordero R. R.
Published: December 2007

A case study is presented which addressed the origin of Hydrogen Sulphide (H2S) in produced gas associated with the oil in Las Heras - Cerro Grande oilfield in Gulf of San Jorge Basin, Argentina.

The reservoir was initially sweet. However, after waterflooding an increase in H2S concentration was detected in several wells. The H2S amount varies across the field with the highest values found in wells where water injection was initiated and the wells produce with a high water cut.

Knowledge of H2S origin contributes to effective control and therefore, to reduce environmental risk, minimize emissions, improve quality of produced hydrocarbons and reduce corrosion rate.

The main stages followed include, H2S measurements, H2S source identification and mitigation treatments.

The possible mechanisms of reservoir souring have been analyzed by sulphur isotope ratio analysis. These results have been integrated with geological factors and other parameters related to waterflooding.

This case is unusual because of water composition. The formation and injection waters have low salinity and are not rich in sulphate ion concentration, very different from sea water composition. Nutrients such as fatty acids are present in both formation and injection waters.

The increase in H2S production is attributed to sulphate reducing bacteria (SRB) living in the reservoir. The proposed model to explain H2S origin suggests a closed system with reactive-limited reaction where H2S production is controlled by low sulphate concentration present in waters.

A strong correlation was demonstrated between produced H2S, injection water parameters and subsequent souring. A decrease in sulphate concentration present in water production appears to correspond with an increase in H2S concentration.

At present, the produced gas is being treated with scavengers. A nitrate injection project is being analyzed to control reservoir souring. The development of a biofilter to oxidize H2S in plant treatment is in laboratory phase.
New Ultra-lightweight Cementing Technology Proven with Case Studies, Combines Benefits of Current Leading Methodologies
Authors: Kulakofsky D. , Araujo O. , Self F. , Mora A. , Hendriks P. , de Mestre P.
Published: December 2007

As the global demand for energy increases, operators are being forced to drill in increasingly challenging environments. Cementing across highly depleted zones and weaker formations requires a dedicated engineering focus and low-density cements that are stretching the limits of current technology. If cement cannot be successfully circulated, a large impact on the drilling cost can be experienced and delays in production delivery can occur due to the required remedial work.

Historically, the industry has relied on two primary technologies for the creation of ultra-light cement slurries - either foaming base cement with nitrogen or through the addition of microspheres to the slurry. While both of these technologies are considered premium solutions and have been used successfully for a number of years, they each have distinct advantages and also limitations when compared to one another.While ideal for certain situations, neither can be used to cover the entire spectrum of today's ever-increasing spectrum of challenges.

This paper presents case histories from Mexico and Oman showing how both technologies, foam and microspheres, have been used in the same design to stretch current lower slurry-density limits, allowing us to meet ever-challenging operational demands. Along with the case histories, guidelines are provided for how to best use these technologies. Details provided from the case histories illustrate how the advantages of both technologies were maximized, while their limitations were minimized.