bluuebunny/crossref_metadata_2025_split huggingface dataset:
Injection Wells: A Case Study From the Statfjord Field
Authors: Andrews J. , Hettema M. , Nesse T. 
Published: December 2007

Abstract
The Statfjord oil field, operated by Statoil in the North Sea, has been on production since 1979. The reservoir management strategy has been water flooding and secondary recovery mechanisms involving gas injection. To date over 63% of the STOOIP has been recovered.
Good injector performance has been instrumental in the economic development of the Statfjord field. The purpose of this study is to investigate injectivity trends in the injection wells in order to understand the processes that influence initial and long term injectivity. This includes thermal fracturing of water injectors and a comparison of injectivity in Water-alternating-gas (WAG) wells during the various cycles of gas and water injection. The Statfjord production database contains large amounts of data for these wells including injection rates and pressures, injection profiles from production logging, and various static pressure measurements.
Fracturing during water injection is found to result in folds of increase in injectivity of between 2 and 4. Whilst the resulting improvements in injection rates have been advantageous for pressure maintenance, out of zone fracturing in some wells has been detrimental to the efficient sweeping of some sand members. Gas injection on Statfjord is shown to be governed by matrix flow and fractures from previous water injection cycles do not stay open during subsequent gas injection in the WAG wells.
Optimization of Commingled Production using Infinitely Variable Inflow Control Valves
Authors: Naus M. M. J. J. , Dolle N. , Jansen J. D. 
Published: December 2007

Abstract
We developed an operational strategy for commingled production with infinitely variable Inflow Control Valves (ICVs) using sequential linear programming. The optimization algorithm requires instantaneous and derivative information. We propose a workflow where the production engineer relies on measurements to determine the flow rate and pressure values, and on models to determine the derivative information, i.e. the changes in flow rates as a result of a change in an ICV setting. Such a model would typically be a steady-state well bore simulator including choke models to represent the ICVs and inflow models to represent the near-well reservoir flow in the various zones. The parameters of the model need to be updated regularly using real-time measurements and production tests, and we discuss the impact of different smart well instrumentation levels on the updating process.
We simulated the performance of this production optimization strategy in a reservoir simulator. Some numerical aspects of the algorithm and problems encountered during implementation are discussed. The performance of the algorithm was tested in two reservoir settings. In both cases, the optimization resulted in accelerated oil production compared to conventional, surface controlled, production. However, accelerated production did not always result in higher ultimate recovery compared to the conventional case. In such situations the benefits of either short-term production optimization (accelerating production) or long-term reservoir management (maximizing recovery) should be weighed.
Simultaneous Estimation of In-Situ Multi-Phase Petrophysical Properties of Rock Formations from Wireline Formation Tester and Induction Logging Measurements
Authors: Alpak Faruk O. , Torres-Verdín Carlos , Habashy Tarek M. , Sepehrnoori Kamy 
Published: December 2007

Abstract
We introduce a novel inversion algorithm for the in-situ petrophysical evaluation of hydrocarbon-bearing formations The algorithm simultaneously honors a set of multi-physics data: (a) Pressure-transient, flowline fractional flow, and salt production rate measurements as a function of time acquired with a wireline-conveyed, dual-packer formation tester, and (b) borehole array electromagnetic induction measurements. Both time evolution and spatial distribution of fluid saturation and salt concentration in the near-borehole region are constrained by the physics of mud-filtrate invasion. The inverse problem consists of the simultaneous estimation of a two-dimensional axisymmetric spatial distribution of absolute permeability and parametric saturation functions for relative permeability and capillary pressure curves. For a given layer, both horizontal and vertical permeabilities are subject to inversion. Saturation functions of relative permeability and capillary pressure are parametrically represented using a modified Brooks-Corey model.
We simulate numerically the response of borehole logging instruments by reproducing the multi-phase, multi-component flow that takes place during mud-filtrate invasion and formation test. A fully implicit finite-difference black-oil reservoir simulator with brine tracking extension is used to simulate fluid-flow phenomena. Electromagnetic-induction measurements are coupled to the physics of fluid flow using a rapid integro-differential algorithm. Inversion experiments consider both noise-free and noise-contaminated synthetic data. Joint inversion results provide a quantitative proof-of-concept for the simultaneous estimation of transversely anisotropic spatial distributions of permeability and saturation-dependent functions. The stability and reliability of the inversions are conditioned by the accuracy of the a priori information about the spatial distribution of formation porosity and fluid PVT properties. For cases where multi-physics measurements lack the degrees of freedom necessary to accurately estimate all the petrophysical model parameters, we develop an alternative sequential inversion technique. The first step involves estimation of horizontal and vertical permeabilities from late-time transient-pressure measurements. Subsequently, the entire set of measurements is jointly inverted to yield saturation-dependent functions.
Rapid Scenario and Risk Analysis for a Complex Gas Field with Large Uncertainties
Authors: Hegstad B. K. , Tollefsen S. , Arghir D. V. , Cullick A. S. , Narayanan K. , Heath D. E. , Lever J. C. 
Published: December 2007

Abstract
Increasingly, the industry is aware of the need to improve field development planning decisions with more rigorous risk analysis. A key is to have technology and work processes supporting the complex evaluation of projects as a whole, i.e. from subsurface to processing with economics, while preserving physical fidelity and interdependent uncertainties. This paper will illustrate how an integrated stochastic approach with scenario analysis, sensitivity analysis, and Monte Carlo simulation assisted an asset team to understand overall project uncertainties and sensitivities for a large gas project. This understanding gave a better basis for the planning decisions.
The richness and speed of the integrated stochastic approach is compared with more conventional case study analysis. The latter requires manual iteration to investigate how variations of input variables as e.g. reservoir properties impact reserves and production. It is followed by manual input to the economic model and manual analysis.
Outputs presented from hundreds of simulations from the integrated stoachastic approach include distributions and histograms of original fluids in place, cumulative production, plateau period, net present value, production rate, discounted cash flows, and rates of return etc. Correlation coefficients between input uncertainties and output uncertainites indicate which input uncertainties give the major contribution to the output uncertainties. This helps the asset team to focus on the important factors for major decisions, and use less time on the less important issues.
Impact of Induced Fractures on Sweep and Reservoir Management in Pattern Floods
Authors: van den Hoek P. J. 
Published: December 2007

Abstract
It is well established within the Industry that water injection almost always takes place under fracturing conditions. Particularly when large quantities of very contaminated water are injected –either for voidage replacement or disposal- large fractures may be induced over time.
This paper presents the results of a study addressing the impact of induced fractures on the "present value" recovery and on the reservoir management in pattern waterfloods. The background of this study is that there exists a general perception that long fractures have a negative impact on recovery. However, this perception is largely based on past studies where only attention was given to recovery as a function of pore volumes injected, not time. In addition, the impact of injection water contamination was never addressed.
Based on streamline simulations on two types of patterns (five-spot and nine-spot), in which the fracture lengths and orientations, in addition to the fluid mobility ratios, were varied, it is concluded that induced fractures in pattern floods generally result in a significant recovery improvement, even for cases in which the induced fractures are "long" (i.e. exceeding roughly 25% of the pattern unit cell size).
In the nine-spot pattern, induced fractures result in by far the largest recovery improvement. It is shown that in this case, the recovery for fractured injection is still significantly above that for matrix injection even when the induced fracture closely approaches one of the producer wells in the pattern unit cell. Furthermore, it is shown that for sufficiently long fractures, the impact of contamination of the injection water on recovery generally is very limited.
Finally, it is demonstrated that depending on pattern type, fracture orientation, and injection water contamination, there exists an optimum induced fracture length that maximizes recovery. This optimum induced fracture length corresponds to that specific injection rate that yields a maximum oil production rate. Because of changing average reservoir fluid mobility over time, this optimum fracture length can only be maintained if injection rates change over the field life. An optimum reservoir management policy should attempt to maintain the induced fracture at its optimum length over the field life by appropriate adjustment of injection rates.
Fluid Sampling and Interpretation with the Downhole NMR Fluid Analyzer
Authors: Akkurt Ridvan , Fransson Carl-Magnus , Witkowsky James M. , Langley William M. , Sun Boqin , McCarty Andrew 
Published: December 2007

Abstract
One of the main applications of MRILab, the recently introduced NMR fluid analyzer, is the estimation of mud-filtrate contamination during the pump-out phase, prior to securing high quality fluid samples for PVT analysis. The NMR fluid analyzer utilizes T1 saturation recovery measurements for contamination analysis. The main objective of this paper is to discuss the principles behind recently developed T1-based novel methodologies that yield accurate and robust contamination estimates. The proposed algorithms were used to estimate the contamination levels in an offshore well drilled with OBM. Comparisons with laboratory assays on nine fluid samples show excellent agreement, thus proving the concept of using an NMR fluid analyzer for contamination analysis in sampling applications. A secondary objective of the paper is to illustrate the benefits of integrating fluid analyzer data with open-hole and NMR logs. Such integration leads to an overall improved interpretation, particularly in terms of hydrocarbon fluid properties.
Shallow Water Flow Geopressures Arising From Confined Subsurface Slumps
Authors: Ruppelt Adrienne U. , West Charles L. 
Published: December 2007

Abstract
Elevated pore pressure within 1000-2500 feet of the seafloor (SWFG or Shallow Water Flow Geopressure) affects the casing program of many wells in the deepwater (&gt;1000 feet water depth) Gulf of Mexico, the Nile delta, and other offshore drilling provinces. When SWFG sands are not properly isolated, a sustained (months in duration) brine flow may occur around the surface casing, leading to buckling of the casing and a large deposit of sand carried to the seafloor by the flow. For a SWFG blowout in the deepwater Gulf of Mexico, cased hole formation test data show the sands involved are sealed by an overlying marine transgressive Sangamon (100,000 Ma) age shale. Even though the four involved sands are separated by less than 60 feet of shale, the sands are also in pressure isolation from each other. Laboratory work on a sample of the sand carried to the seafloor shows large (&gt; 1 p.u.) porosity loss could occur with finite strain cyles at low stress. Using these measured data, variation of seismic response of a flow sand before and during a SWFG well bore failure event has been tentative correlated to porosity losses of 1-2 p.u. A hypothesis is formed for finite strain and porosity loss along a critical stress (at shear failure) path for sand slumping during the shallow water flow event in the GB 515 #1 well. Porosity loss within the isolated or sealed SWFG sand could cause increases in pore pressure above existing levels.
Novel Drilling Fluid Eliminates Tar Problems Associated With Drilling SAGD Wells
Authors: Freeman M. A. , Stoian A. , Potapinski J. W. , Elias L. C. , Tetreault R. 
Published: December 2007

Abstract
Drilling Athabasca tar sand for Steam Assisted Gravity Drainage (SAGD) production is complicated by the sticky bitumen. When the buried tar has high viscosity, it is liquefied in situ and recoverd using SAGD technique. Two wells are drilled around 800 m horizontally, one near the bottom of the deposit and the other about 5 m higher. Steam is injected into the upper hole and the liquefied bitumen is collected from the lower hole.
Tar sands are generally well sorted and poorly consolidated. At typical reservoir temperatures of 10°C, the bitumen is semi-solid. The apparent viscosity of the bitumen appears to halve with each 10°C of temperature increase, and the mechanical heat generated by drilling softens the bitumen and makes it sticky.
Sticky tar adheres to the BHA, causing sand accretion and increasing torque. When the tar reaches the surface, the shaker screens quickly blind off. The sand and bitumen can also separate, building sand beds in the well and forming tar balls that block the flow line. Solvents can be used to dissolve the tar and eliminate screen blinding, but they cause unacceptable wash outs. Mud coolers have been used to remedy the remedy.
A new fluid has been used to drill SAGD wells without adhesion problems or shaker blinding, and without the use of mud coolers. It relies on a strong water-wetting agent to avoid BHA adhesion, oil-wetting surfactants to encapsulate tarry cuttings, and a rheological profile optimized for minimal well-bore erosion.
Although initially troubled with foaming, the lined-out fluid drilled near-gauge holes at rates limited by solids control equipment. Drilling time was reduced compared to similar wells, with similar fluid costs. The new fluid thus offers significant reductions in drilling costs by reducing drilling time and equipment.
Through Tubing Rotary Drilling: A Cost-Effective Method for Sidetracking Wells in Mature Assets
Authors: Kleverlaan Martijn , Lawless Angelique 
Published: December 2007

Abstract
Shell Exploration & Production in Aberdeen, Scotland has implemented through tubing rotary drilling (TTRD) as a cost effective method of accessing small accumulations of hydrocarbons in some of its mature assets in the UK sector of the North Sea. Working together with its contractors, the implementation of TTRD has taken place over the past 6 years. The most recent experience is a 5 well campaign on the North Cormorant platform during the past year. This paper gives an overview of the implementation process including a history of the work done, highlights and lowlights of drilling operations that have taken place to date. However, it focuses on the issues that were addressed in relation to the current campaign. Topics that will be covered are: Planning Process: An evaluation was done leading up to the current campaign to identify the areas of improvement that would yield the highest value. Resources were dedicated to the improvement initiative, beyond what would normally be assigned for conventional drilling operations.Novel Drilling Fluid Application: The conventional weighting agent (barite) was replaced by manganese tetra-oxide to give a low rheology fluid with enhanced anti-sag characteristics.Drilling Performance Optimisation: Work was done to reduce the torque requirement of the drill bits used for TTRD and match those requirements to the capability of the slim hole drilling motors for the required hole size.Equipment Upgrades: Surface equipment and downhole tools were developed and existing tools improved in order to improve performance and increase overall capability. Critical equipment that was either developed or significantly improved included: kick detection equipment, directional drilling bottom hole assembly, perforating guns, and swelling elastomer packers.
The benefit of TTRD, demonstrated by the successful campaign on the North Cormorant, is being carried forward to the rest of the Shell Exploration & Production organisation through the establishment of Global Implementation Team specifically for through tubing drilling. Shell is looking forward to realizing the benefit of this technology worldwide.
Gas Solubility in Synthetic Fluids: A Well Control Issue
Authors: Silva C. T. , Mariolani J. R. L. , Bonet E. J. , Lomba R. F. T. , Santos O. L. A. , Ribeiro P. R. 
Published: December 2007

Abstract
More than 90% of Brazilian oil and gas reserves lie in offshore fields and over 60% of the total reserves are located in deep and ultradeep waters. Some of the important technical problems associated with deep and ultradeep water drilling involve: i) low formation fracture gradients; ii) long choke lines; and iii) low temperatures at the mud line. The well control planning and strategy for drilling exploratory and development wells in those fields should address those technical drawbacks in order to achieve the safety requirements in a cost-effective scenario. The better understanding of gas solubility in synthetic based drilling fluids plays a fundamental role in terms of preventive (kick detection) and corrective (kick circulation out of the hole) well control practices. The present work involves PVT characterization of two organic liquids (n-paraffin and ester) currently applied in drilling fluid systems for deep and ultradeep water drilling, in Campos Basin (Rio de Janeiro, Brazil). The measurement of thermodynamical properties of the methane-liquid mixtures, such as bubble point pressure, solubility, formation volume factor of oil, formation volume factor of gas and liquid density, were performed for 158°F and 194°F temperatures. The measurements were conducted in two different apparatuses: an Hg system and an Hg-free PVT system. The results showed that the correct accounting of formation gas solubility in downhole conditions and during the kick circulation is a very important issue for safely drill deep and ultradeep water wells.
High-Performance Hermetic Optical Fiber for Downhole Applications
Authors: Wang C. , Drenzek G. , Majid I. , Wei K. , Bolte D. , Soufiane A. 
Published: December 2007

Abstract
Optical fibers have been used in the petroleum industry for many years; their applications range from real-time temperature and pressure measurements, data transmission, to imaging applications. In this paper, we demonstrate significantly improved reliability of recently developed hermetic, high operating temperature optical fiber. The study includes extensive testing of this fiber under controlled conditions; and a comparison with previous studies and other non-hermetic fibers.
The hermetic optical fiber of this study is coated with a thin layer of carbon, which provides excellent resistance to hydrogen permeation, water diffusion, and corrosive chemicals attack. Our results show high resistance of the fiber to hydrogen, crucial in the harsh conditions of downhole well completion.
To simulate the harsh environment, a test chamber has been built capable of exposing the fiber to temperatures up to 200°C and pure hydrogen pressures up to 120atm. Attenuation spectra from 0.8 to 1.6μ are recorded before and after exposure. At 150°C and 100atm of pure hydrogen exposure, the induced attenuation at 1.24μ is typically less than 0.4dB/km/100hours. From these spectra, we extract the permeation time constant τf as a function of temperature and thereby obtain the activation energy for hydrogen permeation through the carbon layer. The use of τf is extremely useful to describe carbon coating resistance to hydrogen ingression. Moreover, this parameter allows us to separate the characteristics of the carbon coating from the reaction characteristics of the glass with the ingressing molecules. Our experimental values of τf are significantly greater than previously published results in the literature.
In addition to its high resistance to ingressing molecules, the hermetic fiber of this study also offers enhanced mechanical fatigue resistance determined by both static and dynamic fatigue tests. This improved fatigue resistance is indicated by the high stress corrosion parameter N value ≈ 150.
Spectral Component Geologic Modeling: An Improved Method for Integrating Seismic Data into Geologic Models
Authors: Bishop Glen , Calvert Craig , Foreman Lincoln , Yao Tingting , Bhuyan Kamal 
Published: December 2007

Abstract
Geologic modeling and reservoir simulation provide information critical to successful commercialization of discovered and undeveloped reserves, as well as to the effective management of producing reservoirs. Often, uncertainty associated with the reservoir&s characterization and with the geologic model can be reduced by integrating interpretations from multiple data sources, most commonly from the well and the seismic data. These data types provide very different, yet complementary information to the geologic model. The well data provide information over a broad range of scales, but these data are only sparsely sampled in the reservoir. The seismic data are more densely sampled, but provide only a limited scale of information. The integration of these two data types should properly account for their scale differences. Traditional geostatistical simulation methods do not properly account for the fact that the seismic data and the well data represent very different scales of information.
Spectral Component Geologic Modeling (SCGM) properly accounts for the difference in scale between the seismic and the well data. A spectral component is an interpreted map or volume of a rock property. All spectral components contain information over a limited frequency bandwidth. A tentative geologic model is built by mathematically combining spectral components; each component providing information to the model that is limited with respect to its frequency content. The tentative geologic model is then constrained to honor the desired spatial continuity of the modeled property, the statistical distribution (histogram) of that property, and the properties measured at the well locations.
Spectral simulation is used to honor the desired spatial continuity of the modeled property. With this method, the exact and non-stationary continuity information contained within the combined spectral components can be preserved in the constrained geologic model. As a result, depositional features such as sinuous channel sands, which are observed in the spectral components, are preserved in the model. An application of SCGM is presented. Results clearly show that the SCGM model honors both the spatial distribution and the spatial continuity of the modeled property, as they are represented in the spectral components.