bluuebunny/crossref_metadata_2025 huggingface dataset:
Deepwater Blowout—A Case History: Shallow Gas Hazards Hide in the Weeds
Authors: Flores William Jr. , Garner John B. , Scarborough Chris
Published: December 2007

This paper will detail the sequence of events involving the blowout of a deepwater development well adjacent to the discovery well, while Loop Current prevented running of the BOP stack and riser following the cementing of surface casing. Water depth was 2,400ft. The cause of the blowout was gas flow after cementing.

The operator designed the discovery well to incorporate the pump and dump process and successfully drilled riserless through a shallow gas hazard. Surface casing was run and cemented and the #1 well drilled to the objective depth and completed, pending field development.

The operator spudded the #2 well less than 200ft from the #1 well and duplicated the process, drilling riserless through the shallow hazard and running surface casing. After circulating lead cement to the mud line and observing cement returns at the wellhead, a proprietary cement slurry designed to achieve "right-hand set profile" was circulated into the well as planed.

The drill string was withdrawn and preparations were made to run the subsurface stack and riser. However, Loop Current developed and prevented the running of any equipment until the currents subsided.

Almost three weeks elapsed before the Loop Current abated, at which time the ROV was deployed and discovered the blowout. The plume of the blowout carried over 300ft. This paper will chronicle the extensive effort which the operator expended to reenter the well, perforate, pump kill mud, confirm that the well was static and cement. The conclusion however, is somewhat surprising: three days dormant after cementing the #2 well, while drilling the replacement well, the #2 blew out again. The paper will also present solutions implemented to successfully drill the replacement well.
Pin-Point Fracturing (PPF) in Challenging Formations
Authors: Beatty K. J. , McGowen J. M. , Gilbert J. V.
Published: December 2007

Over 145 pin-point fracturing (PPF) treatments have been performed in Australia's Cooper Basin since the introduction of the technology in mid 2004. The PPF method creates perforations by pumping abrasive slurry down the coil tubing through a jetting nozzle while the main treatment is then pumped down the annulus around the coil tubing. Isolation between fracture treatments is accomplished using sand plugs (preferred method) or composite bridge plugs. Fracturing treatments in the Cooper Basin have historically been problematic due to the combination of high rock strengths (average modulus of sand/shales of 4-5 million psi), proximity to coal formations, high formation temperatures (250-400 deg F), and high fracture gradients (often above 1.0 psi/ft). Screen-outs occur in ~40% of all treatments, so useful experience has been obtained on managing these events. This paper discusses the successful and unsuccessful experiences that have occurred using PPF techniques in these harsh situations. While PPF has improved well performance, the placement of treatments is still problematic. The paper details the experiences with varying abrasive jetting and breakdown techniques, modifying the bottom-hole assembly (BHA), changing the isolation techniques, modifying the treatment schedules, and extending PPF treatments to older wells.
Effect of Shear on Flow Properties During Placement and on Syneresis After Placement of a Polyacrylamide-Chromium Acetate Gelant
Authors: McCool Stan , Li Xianping , Wilhite G. Paul
Published: December 2007

Typical gel polymer treatments to treat fractured rock consist of injecting inline mixed gelant into the reservoir for times usually much longer than the bulk gel time of the gelant. Flow experiments were conducted to determine the effect of shear on the flow properties of the gelant for durations greater than the bulk gel time. Inline mixed gelant was injected through a 1031-ft long tube to simulate a fracture. Flow resistance increased down the tubing to steady values indicating gelation of the flowing system. Similar flow experiments were conducted by injecting preformed gel through the tubing. Flow resistances decreased down the tubing to steady values indicating breakdown of the gel structure. Flow resistances at the steady downstream sections were higher during the injection of inline mixed gelant compared to injection of preformed gel and both were much lower than literature values determined where preformed gel was injected through short fractured rocks and short lengths of tubing. Gel samples underwent syneresis after they were formed during shear flow in the tubing and in a rheometer. Interpretations of flow resistance data from injection of inline mixed gelants and preformed gels in long tubing are presented.
Staircase Lifting of Oil Using Venturi Principle: A New Artificial-Lift Technique
Authors: Gupta Siddhartha
Published: December 2007

Artificial lift systems are now being considered of extreme importance as the reserves across the globe are depleting and the wells are unable to flow naturally. Over the years a number of artificial lift techniques have evolved as a result of extensive research and ground work. All the systems have proven their worth by increasing the productivity of the field by many folds. But each of these artificial lift systems has economic and operating limitations that eliminate it from consideration under certain operating condition. However all the conventional artificial lift systems have a common feature. The energy added to the lift the fluid from the wellbore is lost in the process and cannot be utilized for some other operation.

This paper describes a new technique of artificial lift which uses the concept of venturi to lift the fluid to the surface. A high velocity power fluid is used to create drawdown at the throat of a surface venturi and this pressure drawdown is transmitted downhole by pressure tappings. The drawdown lifts the fluid through the production tubular in a stepwise manner. The power fluid coming out from the other end of the venturi is used to drive a turbine which generates power as a result. This power is used to operate the inlet compressor thus the cycle being completed. After startup, effectively, no energy is used up to keep operating the system.

The system is of immense economic benefit as the operating expenditures are low. Also this system uses zero-cost air as power fluid. It is a space efficient package which can be used on offshore locations as well.

The paper describes the individual components of the system and the calculations involved therein. The economic and technical comparison of this system with the conventional methods is also enlisted.
Modeling Shear Failure and Stimulation of the Barnett Shale after Hydraulic Fracturing
Authors: Palmer Ian , Moschovidis Zissis , Cameron John
Published: December 2007

In the Barnett Shale, microseismic bursts are caused by shear failure on planes of weakness well outside the central fracture plane. Some data show that greater gas flowrate is correlated with a larger "failed reservoir volume", and a higher net fracturing pressure. These aspects have been integrated into a theoretical model. Shear slip or failure along planes of weakness is instigated by pore pressure increases during injection of frac fluid, and pressure transient theory is used to describe that. A knowledge of in situ stress, and strength (or failure envelope) for the planes of weakness, is needed to predict how far away from the central fracture plane this failure zone extends. The failed reservoir volume can be matched to the volume of the microseismic cloud, using injection permeability is the matching parameter. The predictions appear to be reasonable. The injected permeability we obtain is greater than the virgin permeability, and this is interpreted as enhanced permeability due to shear or tensile failure away from the central fracture plane. The permeability enhancement increases as fracturing pressure increases. We have compared the permeability enhancement with history matching of gas production in Barnett Shale wells, and with theoretical matching of Cooper basin data in Australia. The model is a screening model, and may be viable to design a fracture treatment to optimize the enhanced permeability, and the gas production. An advantage of the screening model is its ability to quickly run a number of different scenarios, to choose an optimal stimulation. The model is completely general, and should be applicable to other formations, such as coals and tight sands.
The Optimisation of a Scale Management and Monitoring Program for During the Production-Decline Phase of the Life Cycle
Authors: Jordan Myles , Archibald Ian , Farrell Rod , Johnston Clare , Strachan Alistair
Published: December 2007

This paper presents field results from scale squeeze treatments carried out on platform and subsea horizontal wells from a oilfield in the UK sector of the North Sea. Downhole scale control and the resulting squeeze treatments to production wells were highlighted as one of the most expensive items in the production chemical budget and impacted topside separation during treatment back production. The development of optimized scale squeeze treatments and monitoring policy has been critical to reducing the operating cost and deferred oil production of this asset as the produced water cut rose.

Scale squeeze treatments have been optimised over the years with the aid of detailed reservoir simulation indicating water rates along the production wells being input into scale squeeze design software. The requirement to extend treatment life while minimising the deferred oil was one of the critical factors in selecting improved scale inhibitor chemistry. The field data from these wells will be presented comparing treatment lifetime rates between conventional treatments and the improved scale inhibitor chemistry.

Evaluation of residual chemical concentration or scaling ion chemistry has long been used in monitoring programs. All these methods prove that the chemical is present in the brine when sampled or that scale formation is not occurring at the point of brine analysis. This paper outlines the experimental methods developed to evaluate the suspended solids collected from the produced brine by environmental scanning electron microscope (ESEM) and the associated brine chemistry to evaluate the scale risk within the produced fluids. The combination of these methods has improved the integrated scale management program in terms of evaluating scale squeeze placement effectiveness, squeeze lifetime and providing the confidence to extend the period between scale squeeze treatments and in some cases stop treatment where brine analysis alone would have suggested further scale squeeze applications.
Multiscale Mixed-Finite-Element Modeling of Coupled Wellbore/Near-Well Flow
Authors: Krogstad S. , Durlofsky L. J.
Published: December 2007

An accurate well modeling capability is important for both production and reservoir engineering calculations. Ideally, the models used for these two applications should be related in a logical manner. Multiscale methods allow varying degrees of resolution and can therefore provide a natural linkage between production and reservoir models. In this work, we present a coupled wellbore-reservoir flow model that is based on a multiscale mixed finite element formulation for reservoir flow linked to a drift-flux wellbore flow representation. The model is able to capture efficiently the effects of near-well heterogeneity in the reservoir and phase holdup and pressure variation in the wellbore. The formulation presented here is for oil-water systems. The basic reservoir-wellbore linkage is described and validated through comparison to results from an existing simulator. The multiscale methodology is then applied to a heterogeneous reservoir model. Both vertical and deviated wells are considered. Comparisons of the multiscale solution to the fully resolved (fine-scale) solution demonstrate the high degree of accuracy of the method, for both reservoir and wellbore quantities, as well as its efficiency.
Practical Iterative Coupling of Geomechanics With Reservoir Simulation
Authors: Samier P. , De Gennaro S.
Published: December 2007

The use of reservoir simulation coupled with geomechanics to model physical phenomena such as compaction, subsidence, induced fracturing, enhancement of natural fractures and/or fault activation, SAGD recovery etc.., has been increasing. Different methods of coupling have been investigated by numerous researchers: fully implicit coupling, iterative coupling and one way coupling. So far, the iterative explicit method appears to be the prefered method for field-scale simulation.

This method is a loose coupled approach between a reservoir simulator (finite volumes) and a geomechanical simulator (finite elements). At user-defined steps, the fluid pressures calculated by the reservoir simulator are transmitted to the geomechanical tool which computes the actual stresses and reports the modifications of the petrophysical properties (porosities and permeabilities) back to the reservoir simulator. In the classical iterative scheme, at each stress equilibration step, the reservoir simulation needs to be restarted from the previous converged step. This restart based scheme can be difficult to implement in practice within an industrial IT environment.

This paper presents a new iterative scheme which allows: –any reservoir simulator,–to be coupled with any nonlinear FEM package for the stress analysis, with no limitations on the functionality of either simulator.

This is achieved by performing the pressure/stress iterations at the end of a complete reservoir simulation. Porosity and permeability modifications at various times are calculated, and the complete reservoir simulation is then repeated. Iterations are continued until convergence is achieved.

The convergence of this new scheme is discussed and results are presented for two cases described below.
Effects of Polymers on the Structure and Deposition Behavior of Waxy Oils
Authors: Tinsley Jack F. , Prud'Homme Robert K. , Guo Xuhong , Adamson Douglas H. , Shao Susan , Amin Devang , Callahan Scott , Dettman Heather D. , Kriegel Robert , Saini Rajesh
Published: December 2007

Recent deposition studies have elucidated much of the underlying physics of wax deposition in crude oil pipelines. However, the physics behind polymer additives used to combat wax deposition has not been thoroughly studied. To this end, three types of polymers that have proved effective in reducing the yield stresses of waxy gels have been tested in yield closed-loop laboratory deposition cell. Tests with a multi-component wax solution with polymer additions of 0.1wt% showed that the thickness of the deposit could be estimated from calculations of the height of the cloud point above the cold surface. Such was the case with addition of poly(ethylene butene) polymers (PEB) and the wax solution with no polymer. Conversely, two maleic anhydride co-polymers (MAC) decreased the cloud point and prevented deposition unless the temperature of the cold surface was lowered below the cloud point. However, predictions of the deposit thickness based on cloud point did not hold if erosion occurred. Erosion was always associated with degradation of the microscopic crystal structure, in terms of shape and/or size. The most effective polymers, the MACs, produced the largest change in crystal structure and the most significant erosion. The polymers also produced deposits with the lowest wax contents and the smallest fractions of high molecular weight n-paraffins. However, one EVA polymer that led to thinner, eroding deposits also significantly increased the deposit wax contents, creating hard deposits that would be more difficult to remediate by pigging. Polymers that increased the wax content did not lower the cloud point, even though they may degrade the crystal structure. Thus the importance of both cloud point reduction and degradation of crystal structure was shown. Tests indicated that inhibition of nucleation kinetics may be important for some polymers. Although all polymers reduced the yield stress of the waxy oil when gelled, they did not all decrease deposition. Efficacy in both yield stress reduction and decreasing deposition could be grouped according to polymer type.
Fracture Propagation in High-Permeability Rocks: The Key Influence of Fracture Tip Behavior
Authors: Entov V. M. , Chekhonin E. M. , Detournay E. , Thiercelin M.
Published: December 2007

Pressure distribution at the tip of a hydraulic fracture is a key element for controlling fracture propagation. In low-permeability formations, under downhole reservoir conditions, a severe pressure drop occurs at the tip of the fracture and a lag zone develops due to fluid cavitation. Properly taking into account the controlling parameters of tip behavior has resulted in more accurate and robust fracture propagation models. However, the situation is still unclear in high permeability formations, because the formation fluid can invade the tip zone where the pressure drops below the far-field pore pressure. Moreover, the assumptions of the Carter leak-off model do not apply in this zone.

This work presents a fundamental study of fracture tip behavior in high permeability formations. We consider a steadily propagating fracture, taking into account the flow within the fracture, filtrate leak-off across the fracture faces, and kinetics of filter cake growth. The flow within the reservoir due to leak-off is described by the 2D pressure diffusion equation. The formation is elastic and fracture growth is based on Linear Elastic Fracture Mechanics.

Results show that the tip zone can be either a recirculation zone, in which the formation fluid enters the fracture and then get expelled back into the formation, or is completely filled with fracturing fluid. When the pressure at the tip is higher than the far-field pore pressure, a pressure wave propagates ahead of the tip with severe consequences on fracture propagation. Finally, the total energy consumption (which determines the net pressure) is primarily dissipated in viscous flow within the fracture, leak-off flow across the filter cake, and seepage flow induced by leak-off in the reservoir.

The flow within the reservoir due to leak-off is described by the 2D pressure diffusion equation. The formation is elastic and fracture growth is based on linear elastic fracture mechanics.

This work provides new insight for fracture propagation in highly permeable sandstones and allows us to understand some previously unexplained field and laboratory observations.
Effect of Sampling Strategies on Prediction Uncertainty Estimation
Authors: Erbas D. , Christie M. A.
Published: December 2007

Generating multiple history-matched reservoir models by stochastic sampling to quantify the uncertainty in oil recovery predictions has recently aroused interest in the industry. Coupling a stochastic sampling algorithm with a Bayesian analysis potentially allows incorporation of all sources of uncertainties including data, simulation and interpolation errors. However, the accuracy of the uncertainty estimations strongly depends on the sampling performance. In order to improve the robustness of the coupled Bayesian methodology, the factors that affect the accuracy of the estimations must be examined.

This paper investigates how different sampling strategies affect the estimation of uncertainty in prediction of reservoir production. The sampling strategy involves the choice of algorithm and selection of algorithm parameters in sampling the high-dimensional parameter space. We present examples of using both the Neighbourhood Algorithm (NA) and a Genetic Algorithm (GA) to generate history-matched reservoir models for a real field case from the North Sea.
A Method To Improve the Mass Balance in Streamline Methods
Authors: Kippe Vegard , Hægland Håkon , Lie Knut-Andreas
Published: December 2007

During the last decades, streamline methods have emerged as highly efficient simulation tools that are well-suited for e.g., history matching and simulation of large and complex reservoir models. Streamline methods are based on a sequential solution procedure in which pressure and fluid velocities are computed by solving a pressure equation on a grid in physical space and the fluid transport is computed by solving 1-D transport problems along streamlines. The sequential Eulerian-Lagrangian procedure is the key to the high computational efficiency of streamline methods. On the other hand, it necessitates mapping of saturations (or fluid compositions) back and forth between the Eulerian pressure grid and the Lagrangian streamlines. Unfortunately, this introduces mass-balance errors that may accumulate in time and in turn yield significant errors in production curves.

Mass-balance errors might be reduced by considering higher-order mapping algorithms, or by increasing the number of streamlines. Since the computational speed scales linearly with the number of streamlines, it is clearly desirable to use as few streamlines as possible. Here we propose a modification of the standard mapping algorithm that: (i) improves the mass-conservation properties of the method and (ii) provides high-accuracy production curves using few streamlines.

Mass conservation is improved by changing quantities in the transport equation locally, and we show that these modifications do not significantly affect the global saturation errors as long as a sufficient number of streamlines is used. Moreover, we propose an adaptive strategy for ensuring adequate streamline coverage. The efficiency and accuracy of the modified streamline method is demonstrated for Model 2 from the Tenth SPE Comparative Solution Project. Highly accurate production curves (compared to reference solutions) are obtained in less than ten minutes using one processor on a standard (Intel Core 2 Duo) desktop computer.
Development of a Methodology for Hydraulic Fracturing Models in Tight, Massively Stacked, Lenticular Reservoirs
Authors: Green Christopher A. , Barree Robert D. , Miskimins Jennifer L.
Published: December 2007

This paper describes and critically assesses a common methodology currently used to model hydraulic fractures in geologically complex, fluvial, tight gas reservoirs. A planar 3- D fracture simulator is used with a fully coupled fluid/solid transport simulator. The model incorporates a unique data set from the Piceance basin, Colorado, which produces hydrocarbons from the Cretaceous-age Mesaverde formation. Initially, vertical variations in geo-mechanical rock properties (Young’s modulus, Poisson’s ratio and Biot’s constant) were calculated from well logs. The results were then compared with previous work undertaken on the Mesaverde formation and carried out at the DOE/GRI MWX site. From this analysis, specific correlations were developed for rock properties derived from well logs on a foot-by-foot basis to be used in the hydraulic fracture model. Diagnostic mini-frac injection tests of individual sandstone reservoirs were used to confirm model inputs and develop a valid stress model.

Previous attempts to model hydraulic fracture growth in the Mesaverde have been hampered by a lack of detailed input data sets and the inability to accurately determine horizontal rock property variations. This paper outlines a method which uses micro-seismic/tiltmeter data to constrain and verify the model inputs. The resulting frac model is shown to have not only matched the fracture containment but also pressure matched the actual net surface pressure data in this extremely geologically complex area. From these results it is possible to get a better understanding of how fracs grow and interact with complex fluvial reservoirs, allowing operators to better optimize field well performance and completion methods in these geologic settings. Additionally, the minimum critical data required to develop such a model has been identified and will aid operators in developing their data acquisition programs. Although developed in the Rocky Mountain region, the presented technique can be extrapolated to other similar geologically complex reservoirs world-wide.
Implications of Geomechanical Analysis on the Success of Hydraulic Fracturing: Lesson Learned from an Australian Coalbed Methane Gas Field
Authors: Rahman Khalil , Khaksar Abbas
Published: December 2007

Hydraulic fracturing is a widely used technology in the petroleum industry to increase production rates from low- permeability reservoirs. It has also been successfully applied to coalbed methane gas development in many occasions. This paper presents an Australian field case of coalbed methane gas development where expensive fracture treatments did not yield the expected benefits. A comprehensive integrated geomechanical analysis was performed to understand the underlying causes for the failure. The geomechanical model consists of the magnitude and orientation of the three principal stresses, the pore pressure, and the rock strength. Fracture treatment data were used to estimate the least principal stress, vertical stress was determined from density logs, pore pressure was derived from direct field measurements, and rock strength values were determined from well logs and core measurements. The maximum horizontal stress (SHmax) magnitude was constrained by modeling the stress and pressure conditions consistent with the observation of wellbore breakouts in image logs. The relative magnitude of principal stresses corresponds to a transition between Strike- Slip and Reverse Faulting stress regimes (SV ≤ Shmin ≤ SHmax) with an overall SHmax orientation of NE-SW. Fracture propagation simulations using boundary element modeling showed that a complex fracture growth under the influence of the current in-situ stresses could be the main reason for the fracture treatment failure. The study recommended a number of alternative configurations for well orientations and fracture treatments in the field considering the existing in situ stress and the complex fracture network. Also the interactions between the coal seam and different fracturing fluids have been studied to evaluate the formation damage aspects to recommend the formation compatible fracturing fluid. Presentation of these results in this paper is expected to give a general framework for successful hydraulic fracture treatments and example of specific implementation issues with respect to an Australian coalbed methane gas field.
Coiled-Tubing Gyro MWD Improves Kickoff Direction Accuracy for Cased-Hole CTD Re-Entry Drilling
Authors: Madarapu R. , Corson C. S. , Grant D.
Published: December 2007

Coiled tubing drilling (CTD) is an economical method of re-entering existing cased wells in mature fields to exploit bypassed reserves because of its versatility in accommodating a variety of candidates and its technological edge in drilling more efficiently.

In re-entry drilling, kicking off with the right bearing attenuates the single biggest issue when drilling long laterals—weight transfer problems. Correct re-entry wellbore placement from vertically cased wells has traditionally required many single-function trips. The magnetic interference from the steel casing makes the acquired magnetic tool face measurements from traditional instruments inaccurate. Verification of the kickoff direction is usually performed with a wireline multi-axis gyro instrument. This process can be time-consuming and still requires additional correctional runs or directional changes prior to beginning drilling in the desired direction toward the target.

Hence, the entire process of intervention, from setting a whipstock in the right orientation to drilling in the least tortuous direction from these vertically cased wells, requires a more efficient approach if CTD is to be a viable option in marginal projects.

This paper assesses the limitations in the current methods of kicking off and details an innovative approach to improve re-entry wellbore quality through the use of an integrated coiled tubing gyro measurement-while-drilling (MWD) instrument.
Use of Microbial DNA Probes as a Potential New Tool in Oil Exploration and Characterization
Authors: Kotlar Hans Kristian , Brakstad Odd Gunnar , Markussen Sidsel
Published: December 2007

There are numerous examples of microorganisms isolated from oil reservoirs, yet very little is known about the microbial ecology and in situ microbial metabolic processes of reservoirs. Such processes may have a great impact on oil quality and recovery. The oil reservoir constitutes a unique microbial habitat with respect to temperature, pressure, salinity, pH and nutrient availability. Even though oil reservoirs are considered anaerobic, also strains classified as more "aerobic" have been isolated and are thought to be of indigenous origin. Molecular methods have only recently started to be employed in exploring oil reservoir microbiology. Such analyses have mainly focused on determining the diversity of species present using 16S rDNA sequencing and other forms of direct sequence information. Through our biotech-project 16S ribosomal RNA gene libraries have been made on organisms found in different North Sea fields, fields in South America and Asia. From these libraries specific selected target organisms associated with oil and gas have been found. This has been developed into different DNA probe-like tests. It is interesting to note that similar bacteria have been isolated from different oil fields located very far from each other. This paper will focus on the use of this new non-invasive tool for finding/detection of oil. Field examples from differentiation of gas seeps and new evidence to the infill history of a North Sea reservoir will be given. This methodology can also be used for finding of new oil and gas in sensitive areas and for monitoring of existing production.
A Rigorous Pore-to-Field-Scale Simulation Methodology for Single-Phase Flow Based on Continuous Time Random Walks
Authors: Rhodes Matthew E. , Bijeljic Branko , Blunt Martin J.
Published: December 2007

We demonstrate a pore-to-reservoir simulation methodology and apply it to singe-phase flow. Traditional numerical methods are based on the discretization of partial differential equations with known spatially-dependent coefficients, such as porosity and permeability. However, in porous media flow we do not know a priori what the governing transport equations are − for instance, single-phase transport cannot be accurately described by an advection-dispersion equation − nor do we know the reservoir properties everywhere.

We propose a different approach that does not pre-suppose the functional form of the upscaled transport equations and which automatically accounts for uncertainty in the reservoir description. Single-phase transport is modeled as a continuous time random walk. Particles make a series of transitions between nodes with a probability ψ(t)dt that a particle will first arrive at a node from a nearest neighbor in a time t to t+dt. A top-down multiscale approach is used to find the flow field. At the micron scale, ψ(t) for particle transitions from pore to pore are found from modeling advection and molecular diffusion in a geologically representative network model. This ψ(t) is used to compute transport on the mm to cm scale. At larger scales, we represent the reservoir as a network of nodes connected by links. For each node-to-node transition, we compute an upscaled ψ(t) from a simulation of transport at the smaller scale. We account for small-scale uncertainty by interpreting ψ(t) probabilistically and running simulations for different possible realizations of the reservoir model. To make the number of computations manageable, ψ(t) is parameterized in terms of sub-scale heterogeneity and Peclet number, meaning that only a few representative simulations are required.

We demonstrate the methodology by finding ψ(t) for pore-scale flow and using it in a million-cell reservoir model. We show that the macroscopic behavior can be very different from that predicted by assuming that the advection-dispersion equation operates at the small scale. Small-scale structure does impact macroscopic transport; increasing the pore-level heterogeneity delays breakthrough and leads to longer late-time tails of the production since the solute spends more time in slow-flowing regions of the domain. We discuss extensions to multiphase flow and the development of a novel network-based probabilistic reservoir simulation approach.
Decline Analysis for Horizontal Wells of Intercampo Field, Venezuela
Authors: Dou Hong'en , Chen Changchun , Chang Yuwen , Fang Yanjun , Chen Xinbin , Liu Wei , Cai Wenxin
Published: December 2007

Intercampo oilfield is characterized by heavy oil with mid-high permeability and high oil saturation, which is an unconsolidated reservoir driven by edge water and bottom water. This paper presents the oilfield's application of three decline analysis models to the 13 horizontal and 13 vertical wells of the oilfield respectively, as well as the comparison of the decline features between vertical and horizontal wells. The authors point out that the decline analysis models are not only applicable for vertical wells but also for horizontal wells. Although the water cut rising of horizontal wells are different from vertical wells, the authors emphasize the well type and reservoir properties are not associated with the decline analysis models. In regards to screening and comparing of decline analysis models; how to select and use the models; their application condition; and the models features are clearly presented in this paper.

The paper introduces two new decline analysis models for horizontal wells. They have been applied to predict production rate of the oilfields, reservoirs, and wells, as well as their future trends. The results accord well with the actual data from the oilfield. The classical models screened out and the new models were recommended analyzing the production performance of the oilfields and reservoirs for the types of wells.
19F NMR Study of Ovalbumin Diffusion in Guar Filter Cake
Authors: Fu Lin , Pethica Brian , Prud'homme R. , Pacheco Carlos
Published: December 2007

Enzymatic degradation is commonly used to degrade the filter cakes formed from hydraulic fracturing fluids (guar solution). In this highly concentrated filter cake, enzymatic degradation kinetics is diffusion-controlled. It becomes crucial to understand the diffusion process of enzymes in the polysaccharide gel layer. The transport of a protein that mimics the enzyme protein (i.e. ovalbumin) in concentrated polymer solutions (hydroxylpropyl guar), including both translational diffusion and rotational diffusion, has been studied by NMR. Translational diffusion is required to degrade the filter cake over long length scales, but rotational diffusion is necessary for the enzyme to bind to the guar chains to initiate degradation. The proton NMR signal for protein/polymer systems is too complicated to be applied in practice. A CF3 group, which is chemically tagged to protein by reacting with S-ethyl trifluorothioacetate, is introduced to differentiate the protein from polymer matrix and reduce the complexity.

19F pulsed field gradient NMR is used to measure the translational diffusion coefficient, while T1 and T2 relaxation of the 19F signal is measured to obtain the rotational diffusion coefficient. Translational and rotational diffusion coefficients are compared with Stokes Einstein (SE) equation. Both diffusion coefficients deviate from Stokes Einstein (SE) equation significantly. For translational diffusion, this deviation indicates that on the length scale of the protein size the protein molecule feels inhomogeneity of the matrix polymer. This results in a 67% decrease in protein mobility when the matrix polymer concentration is only 5wt%. The rotational diffusion coefficient is found to stay relatively constant when the tracer size is much smaller than the mesh size of polymer matrix, which is consistent with the SE equation. But when the protein size is comparable to the mesh size of polymer solution, the SE model fails. In this range, proteins only feel a fraction of the hydrodynamic interaction of the polymer matrix and the relationship between the rotational diffusion coefficient and macroscopic viscosity is found to obey a power law. Further, experimental results are compared with effective medium theory and confined diffusion model, from which we can see that proteins are confined by "dynamic" polymer chains.
The Importance of Fluid Chemistry in High-Temperature Hydraulic Fracture Stimulation
Authors: Shelley Bob , Harris Phillip C.
Published: December 2007

This paper presents the results of a data-driven field modeling (DDFM) evaluation applied to a high-temperature reservoir in Australia for the purpose of determining the significance of chemistry, reservoir, well, and hydraulic-fracture characteristics on well production. The DDFM approach has identified key production drivers for a gas-well field in Australia. This information has been useful to explain hydraulic fracture well production and provide guidelines for future fracture stimulation success.

A DDFM process was used to develop a model for 32 wells completed in a complex, 250 to 350°F gas reservoir in Australia. This type of modeling technique uses data from the field, including chemical formulation, geology, reservoir, well, completion, hydraulic-fracture stimulation, and production results. The data is integrated into a common format and resolution, then visual and statistical evaluation is performed. Relevant correlations and useful trends are noted. Next an effort is made to develop a predictive model that can be used to provide an overall explanation as to what parameters drive production in the well field. Or, in effect, derive a high-level understanding about the effect of the fracturing process on the reservoir. This is accomplished by the use of data modeling/optimization technologies, including artificial neural network (ANN) and genetic algorithms.1-3 The resulting ANN model can then be used to evaluate the production associated with various hydraulic fracturing scenarios and/or characteristics. Validation of conclusions and/or resolution of difficult interpretation issues are done by detailed evaluation and modeling of key wells.

Hydraulic-fracture stimulation scenario evaluations performed by the ANN model have yielded some expected and some unexpected results. As expected, reservoir characteristics such as pay thickness, porosity, and water saturation have a dominant effect on well production. What was unexpected is the significance of well operations and stimulation fluid chemistry on well production. The practice of killing the well after stimulation and using inappropriate perforation techniques can reduce gas production by as much as one-half, while the use of a high-temperature gel breaker in combination with a reduction in base-gel polymer load can provide a 67% increase in production.
Quasimonotonic Continuous Darcy-Flux Approximation for General 3D Grids of Any Element Type
Authors: Pal Mayur , Edwards Michael G.
Published: December 2007

A family of flux-continuous, locally conservative, finite-volume schemes has been developed for solving the general geometry-permeability tensor pressure equation on structured and unstructured grids and are control-volume distributed [1,2]. The schemes are applicable to the general tensor pressure equation with discontinuous coefficients and remove the O(1) errors introduced by standard reservoir simulation (two-point flux) schemes when applied to full tensor flow approximation. The family of flux-continuous schemes is quantified by a quadrature parameterization and has been tested for ranges of quadrature points. Specific points have been observed to yield improved convergence for the family of flux-continuous schemes for structured and unstructured grids in two dimensions [3].

This paper presents a complete extension of the family of control-volume distributed (CVD) multi-point flux approximation (MPFA) flux-continuous schemes for general three dimensional grids comprised of any element type, hexahedra, tetrahedra, prisms and pyramid elements. Discretization principles are presented for each element. The pyramid element is shown to be a special case with unique construction of the continuity conditions. The Darcy flux approximations are applied to a range of test cases that verify consistency of the schemes. Convergence tests of the three-dimensional families of schemes are presented, with emphasis on use of quadrature parameterization. Monotonicity issues are also discussed and tests performed confirm optimal monotonicity of the schemes as determined by an M-matrix analysis [1].
Understanding the Factors Influencing the Formation and Control of Calcium Naphthenate Solids and Stabilised Emulsions Using a Novel Laboratory Flow Rig
Authors: Williams Helen , Dyer Sarah , Graham Gordon
Published: December 2007

The formation of calcium naphthenate solids and stabilised emulsions continues to be a major flow assurance issue. The ability to replicate the conditions under which naphthenates form in the laboratory has, until recently, been an unresolved challenge. Recent work by the authors has resulted in improved test methodologies, utilising a novel flow rig. The rig enables the study of the formation and control of naphthenate solids and stabilised emulsions under field-representative conditions, and allows the prediction and control of their occurrence in the varying production conditions that may be experienced over a field’s lifetime.

This paper describes the use of the flow rig to test a number of crude systems, some of which have known calcium naphthenate problems, and some of which are known to have no calcium naphthenate issues. The results from the flow rig have been compared with field observations and show excellent correlation. Data is then presented which more directly assess the influence of a number of variables, such as water-cut, brine composition, bicarbonate level, and pH, on emulsion stability and naphthenate formation than has previously been possible under conventional laboratory test methodology. This work therefore extends our understanding of "practical" naphthenate formation.
Continuous Reservoir Model Updating Using Streamline-Assisted Ensemble Kalman Filter
Authors: Arroyo-Negrete E. R.
Published: December 2007

The recent use of the ensemble Kalman filter EnKF for data assimilation and assessment of uncertainties in future forecast in reservoir engineering seems to be very promising. It provides ways of incorporating any type of production data or time lapse seismic information in an efficient way; however, the use of the EnKF in history matching comes with its share of challenges and concerns. The overshooting of certain values in the permeability field, possible increase in the material balance errors of the updated phase(s), and limitation to work with non-Gaussian permeability distribution are some of the most critical problems of the EnKF. The use of larger ensemble size may mitigate some of these problems but are prohibitively expensive to implement.

This paper presents a conditioning technique that can be implemented with the EnKF, which eliminates or reduces the magnitude of these problems. This allows for the use of a reduced ensemble size, thereby leading to significant saving in time during field scale implementation. Our approach involves no extra computational cost and is easy to implement. Additionally the final history matched model tends to preserve most of the geological features of the initial geologic model.

A quick look at the procedure is provided here. It enables implementation of this approach into current EnKF algorithms. We demonstrate the power and utility of our approach with an example.
History-Matching Multiple Attributes With Streamlines and Statistics
Authors: Gross H.
Published: December 2007

Geological consistency is often overlooked in history-matching problems, yielding matched models taht do not respect geological considerations. In reservoir modeling, geological consistency takes two aspects: the first is consistency in space, the second is consistency between the different properties. Consistency in space has been addressed in previous work, and a solution was found in the usage of local, flow-based, corrections as secondary information to a geostatistical simulation algorithm. Consistency across properties is the need for parameters such facies type, permeability, porosity, or net-to-gross, amongst others, to obey certain rules of inter-dependence. Honoring the relations across properties when correcting one parameter based on flow considerations is the topic of this paper.

Instead of using a simple analytical correlation for all collocated properties, we use a statistical treatment of field data gathered either through pore network modeling or through analog models. The central idea of this technique is to compute probabilities of occurrence of any given combination of properties, and once a correction is computed on one given property, other properties are updated according to the prior probabilities.
Management of Sulfur Disposal by Acid Gas Underground Injection
Authors: Vidiuk K. E.
Published: December 2007

In the ‘sweetening’ of natural gas, many waste byproducts are created; among these wastes is H2S. In this work the injection of pure H2S into a deep aquifer as a means of disposal and sequestration has been studied using a compositional numerical reservoir simulator. The primary concern of this study is the evolution of the area of influence of the H2S gas front through the aquifer. The study incorporated a sensitivity analysis to determine which parameters have the greatest effect on the area of influence of the gas. Once this is established, those that are controlled parameters may subsequently be optimized, and those that are aquifers properties may later become part of a selection process in choosing aquifers for H2S disposal. This will also determine which properties of an aquifer must accurately be tested in order to better predict the area of influence and behavior of the gas.
Rigless Installations of Safety Valves to Implement a Well-Integrity Campaign and Return Wells to Production
Authors: Afolabi Folorunso , Lacy Rodger , Asher Robert , Butler Bobby
Published: December 2007

Protecting the environment and health of the people by ensuring the integrity of all wells is one of the must-obey policies in Shell Petroleum Development Company of Nigeria Limited (SPDC). SPDC has been the leading producer of crude oil in Nigeria for more than 50 years. SPDC produces from many brown fields. SPDC currently has an inventory of producing wells that have been shut in because of one form or another of wellbore integrity problems. In some cases, these wells were completed decades ago when HSE requirements were considerably less stringent than they are today and wells were completed without sub-surface or downhole safety valves.

In 2003, a more stringent policy on non-integrity wells was introduced and led to an investigation of service providers for a more reliable rigless installation of safety valves or a more cost effective rig workover. However, most of the brown fields that encompass these wells are predominantly located in the Niger Delta both in the shallow waters offshore and in land locations including swamp areas. Many of the wells are located on small-unmanned production jackets which do not have the structural integrity to support even an electric line unit let alone a workover rig. In addition the current geopolitical situation in the Niger Delta is such that bringing in any heavy-duty equipment can be extremely difficult and highly uneconomical in most of these low producing wells.

It was against this background that SPDC carried out a well integrity management campaign to examine the feasibility of some kind of economic intervention to bring these wells back onto production.

In this paper the authors will examine in detail the prevailing situation, present details of the alternative solutions that were considered and describe a highly economic campaign that was put in place to rehabilitate some 40 wells and make available some 30,000 bopd of oil production, all without the use of major workover equipment.