bluuebunny/crossref_metadata_2025_split huggingface dataset:
Protecting Reservoir with Surfactant Micellar Drill-in Fluids in Carbonate-Contained Formations
Authors: Huang Tianping ‘Tim’ , Crews James B. , Clark David E. 
Published: February 2011

Abstract
Conventional water-based drill-in fluids contain high molecular weight polymers and different size-distribution solid particles to reduce fluid loss and carry drilling debris back to surface during the drilling process. The polymers and solid particles in the drill-in fluids usually generate near wellbore formation damage.
This paper introduces a new polymer-free and solids-free surfactant micellar-based drill-in fluid system to drill a carbonate-contained reservoir. This new fluid system contains relatively low reactivity acids mixed with surfactants and internal breakers. The drill-in fluid is designed to have low viscosities in the drillpipe. After the fluid flows out of the drill bit, the acids will react with carbonates in the formation thereby increasing the pH of the drill-in fluids. The higher fluid pH combined with the presence of dissolved divalent ions will cause the surfactants to form elongated micelle structures that will significantly increase fluid viscosity at the bottom of the hole and in the downhole annulus between the drillpipe and the formation rock. The viscosified drill-in fluid will reduce fluid loss and will carry non-dissolved drilling debris to the surface. After drilling through the targeted formation, the internal breakers in the viscosified drill-in fluid will break down the fluid viscosity to permit their removal, and the well will produce with very little or no near-wellbore damage.
A Modified Genetic Algorithm for Horizontal Well Placement Optimization in Gas Condensate Reservoirs
Authors: Morales A. , Nasrabadi H. , Zhu D. 
Published: February 2011

Abstract
Determining optimum well locations is a crucial step in field development. Often, broad possibilities and constrains on computational resources limit the scenarios that can be considered. When dealing with heterogeneities, the intuitive engineering judgment may not be sufficient, and use of optimization algorithms becomes necessary in finding a favorable production plan.
Although there have been extensive publications on optimization algorithms for oil reservoirs, there is little research aimed at gas or gas condensate reservoirs. In this work, we studied optimization of horizontal well placement in gas condensate reservoirs. One of the current challenges in development of gas condensate fields is condensate blockage. As pressure decreases condensate accumulates around the wellbore, leading to significant reduction in gas production. Horizontal wells can effectively solve this problem. However, due to their high cost, and complex phase behavior determining optimum locations cannot be based only on intuitive judgments.
Here we present a horizontal well-placement optimization method for gas condensate reservoirs based on a modified genetic algorithm. Unlike oil reservoirs, the cumulative production in gas reservoirs does not vary significantly (although the variation is not economically negligible) and there are possibly more local optimums. Therefore the possibility of finding better production scenarios in subsequent optimization steps is not much higher than the worse case scenarios, which delays finding the best production plan. In this work, we use a cumulative distribution function to magnify the difference between production scenarios. As a result of this change we were able to find the best scenario with considerably fewer simulations. We apply the modified algorithm to a section of Qatar's North Field, a gas condensate field with the world's largest gas reserves. Our results show that this method can efficiently find the optimum horizontal well locations and can lead to valuable increase in gas and condensate production.
Drilling Expert System for the Optimal Design and Execution of Successful Cementing Practices
Authors: Al-Yami A.S. , Schubert Jerome , Medina-Cetina Zenon , Yu Ok-Youn 
Published: February 2011

Abstract
Cementing is an important factor in drilling and completion operations. Good cementing practices are required for a proper advancing in drilling and production operations. Successful cementing practices start with the design of effective cement slurries. However, to the best of the authors’ knowledge, there are no standard guidelines to help drilling engineers and scientists in the effective design of optimal cement slurries to be used in different well sections.
The objective of this paper is to propose a set of guidelines for the optimal design of cement slurries, by integrating current best practices through a decision-making system based on Artificial Bayesian Intelligence. Best cementing practices collected from data, models, and experts’ opinions, are integrated into a Bayesian Network BN to simulate likely scenarios of its use, that will honor efficient designs when dictated by varying well objectives, well types, temperatures, pressures, and, drilling fluids.
The proposed decision-making model follows a causal and an uncertainty-based approach capable of simulating realistic conditions on the use of cement slurries during drilling and completion operations. For instance, well sections and drilling operations dictate the use of the proper cement design which may include the use of specific additives according to the particular modeling scenarios. These include operations on surface casing, top jobs, intermediate casings, cementing in weak formations, squeeze treatment, kickoff and isolation plugs, horizontal, and vertical completions, among others. Potential operational problems that can lead to cementing failures are also discussed. Different methods of investigation and recommendations are presented in detail.
In-Situ Combustion Dynamics Visualized With X-Ray Computed Tomography
Authors: Hasçakir B. , Castanier L. M. , Kovscek A. R. 
Published: February 2011

Abstract
One method to access unconventional, heavy-oil resources is to apply in-situ combustion (ISC) to oxidize in place a small fraction of the hydrocarbon thereby providing heat and pressure that enhances recovery. ISC is also attractive because it provides the opportunity to upgrade oil in-situ by increasing the API gravity and decreasing, for instance, sulfur content. Despite a considerable literature on ISC dynamics, the propagation of a combustion front through porous media has never been visualized directly. We use X-ray computed tomography (CT) to monitor ISC movement, displacement-front shape, and thickness in a 1m long combustion tube. Temperature profile history, liquid production, and effluent gas data are also obtained. Tests employ a 8.65 °API (at 21.6 °C) heavy crude oil and representative sand. The general trend of saturation profiles are defined through spatially and temporally varying CT numbers. The role of initial oil and water saturations is examined by packing the combustion tube with either multiple samples with different saturations or filling it with a uniform sample. Our work quantifies that ISC fronts display instabilities on a very fine scale (cm). ISC reactions appear to add to front instability in comparison to inert gas advance. The pressure gradients during ISC appear to influence grain arrangement for loose packing. These grain arrangements cause combustion front fingering suggesting that the geomechanical state is relevant to combustion. This new data advances the knowledge base significantly by providing a data set for benchmarking of ISC simulations.
Field Data Validation of a General Model for High-Performance Fractures in Deviated High-Rate Wells
Authors: Marongiu-Porcu M. , Naha S. , Norman D. , Ehlig-Economides C. A. 
Published: February 2011

Abstract
The use of deviated trajectories in deepwater completions is legitimately advocated by drilling constraints, but unfortunately production considerations have not been given the attention they deserve. A recently developed comprehensive semianalytical model using distributed volumetric sources offers a flexible and powerful computational tool that enables rigorous evaluation of a wide variety of possible flow patterns, including augmented wellbores due to "halo effects", combined flow towards the fracture and towards the remaining flowing perforations not connected to the fracture, turbulent flow effects and possible different levels of damage within the fracture and gravel pack regions.
While the generalized high-performance fracture (HPF) model clearly indicates the well performance penalty for hydraulically fracturing a deviated well, for many operators the main reason for the hydraulic fracture is sand control. The high-performance fracturing (frac-pack) completion has proven to last for a significantly longer time and through much greater cumulative production than conventional (non-fractured) cased hole gravel pack (GP) completions. A key reason for the success in deviated wells may be that even though much of the flow to the well may bypass the hydraulic fracture, as long as flow to the well is mostly uniform, the potential for failure is low.
This paper provides a broad based validation of the model using field data from a key deepwater region. Production and pressure transient data, and open and cased hole logs are used to evaluate the most likely flow geometry for each field case, and the results are compared to HPF model output. This provides a global assessment of the model versatility in modeling the production behavior of actual wells. In turn, this enables use of the model to benchmark the performance of any given well to what it could have had with more nearly optimal drilling and completion practices.
New Remediation Technology Enables Removal of Residual Polymer in Hydraulic Fractures
Authors: Crews James B. , Huang Tianping 
Published: February 2011

Abstract
Over the past decade, the majority of wells drilled have required hydraulic fracturing treatments to become economically profitable. The primary objective for hydraulic fracturing is to create a high-conductivity path from the wellbore to deep within the hydrocarbon-bearing reservoir. The most widely used fracturing fluid systems have been crosslinked polymer fluids. These fluids exhibit exceptional viscosity, thermal stability, proppant transportability, and fluid leakoff control. However, a major drawback of crosslinked polymer fluids is the amount of polymer residue they too often leave behind, which causes fracture conductivity loss.
This paper presents new remediation technology that will enable post-treatment removal of residual polymer from hydraulic fractures. The new technique uses nanoparticle-associated surfactants in brine that generate crosslinked-polymer-like fluid viscosity. The new fluid technology offers wall-building leakoff control that will help direct and keep the treatment fluid within the hydraulic fracture. Discussed is how new internal breakers have been developed, which remain within the surfactant micelle structures wherever they go during the treatment. After targeted remedial fluid placement and micelle breaking within the hydraulic fracture, polymer breakers held by viscosity are released to degrade the residual polymer mass within the fracture. Further presented are the components, mechanisms, and performance characteristics of the surfactant micellar fluid system and its potential for removing residual crosslinked polymer from proppant media.
Estimating Near-Wellbore Permeability in Horizontal Wells From Distributed Pressure Measurements Using an Adjoint-Based Minimization Algorithm
Authors: Zinati F. Farshbaf , Jansen J. D. , Luthi S. M. 
Published: February 2011

Abstract
Recent developments in the deployment of distributed pressure measurement devices in horizontal wells carry the promise to lead to a new, cheap and reliable way of monitoring production and reservoir performance. We theoretically examine the identifiability of reservoir parameters from distributed pressure measurements in the well. The wellbore and near-wellbore are described by semi-analytical steady state models, and a gradient-based inversion method is applied to estimate the permeability of layers that are perpendicular to the wellbore axis. To obtain the derivative information we employ the adjoint method which results in a computationally very efficient inversion scheme. Through several synthetic examples we investigated the effects of well and reservoir parameters, sensor spacing, and measurement noise on the quality of the inversion results. In particular we considered a 2000 m long horizontal well passing through two 300 m long high-permeability streaks in a 10 times lower permeability background. The location of high-permeability zones could be detected with a fair accuracy using 20 unknown parameters (specific PI values) even when the number of measurements was four times less than the number of parameters. Moreover, with 0.01 MPa (1.5 psi) measurement noise (and an average wellbore pressure of approximately 20 MPa (3000 psi)) the estimated specific PI profiles were satisfactory and the high permeability streaks were still detectable. However, when the noise level increased to 0.1 MPa, only the high permeable zone close to the heel was detectable. The negative effects of measurement noise and low sensor/parameter ratios are strongest in those areas of the well where the influx is smallest (usually close to the toe). The inversions typically required less than 90 seconds on a standard laptop. This offers the opportunity to extend the algorithm to multi-phase flow and dynamic applications (pressure-transient testing) while still maintaining sufficient computational speed to perform the inversion online.
Drilling Mechanics Challenges and Strategies to Reach New Exploratory Deepwater Frontiers in Brazil
Authors: Arevalo Y.I. , Medina Y. , Naslausky A. 
Published: February 2011

Abstract
The recent discoveries made in the presalt arena and confirmations of its huge potential have started an unprecedented exploratory campaign in ultra-deep waters by many different players. These exploratory wells are drilled in water depths exceeding 2000m with various drilling challenges depending on each specific area; however, it has been observed that to varying degrees all the wells share a common challenge of drill string failures resulting from extreme drilling dynamics events in vertical hole sections.
Conventional practices for mitigation of drillstring shock and vibrations have often proved ineffective in the mitigation of destructive vibration scenarios, and the decision to continue drilling ahead under such conditions has resulted in catastrophic outcomes. We have observed twist-offs, back-offs and BHA component failures related to shocks and vibrations.
The analysis of these recent case histories revealed that using state-of-the-art drilling monitoring tools coupled with real time optimization of parameters was not sufficient to effectively prevent the occurrence of catastrophic events. For this situation to be improved, a technique that calculates a coefficient based on the severity of drillstring vibrations to estimate the remaining life of drillstring components in real time was used as a guideline for improving decisions on when to pull out of the hole to replace and inspect drilling assemblies, thus reducing the risk of catastrophic failures. Using advanced vibration sensors to discriminate between different types of vibrations was critical estimating realistic BHA component equivalent life, which was demonstrated to be highly dependent on the type of vibration suffered by the assembly and the onset of vibration modes coupling.
The proposed approach of integrating drilling mechanics information with real-time estimation of the BHA life is proved in seven exploratory projects as a technique to assist in the prevention of catastrophic drillstring failures.
Source-Mechanism Studies on Microseismicity Induced by Hydraulic Fracturing
Authors: Warpinski N. R. , Du J. 
Published: February 2011

Abstract
While microseismic mapping has proven to be a valuable technology for understanding hydraulic-fracture growth and behavior, the seismic waves generated by the microseismic event also contain information that has potential value for understanding the reservoir, natural fractures, stress state, and fracturing mechanisms. Extracting information from the microseismic data requires the use of a source model, which in its most general form is represented by a symmetric moment tensor having six components. Difficulties arise when attempting to invert for the components of the moment tensor if only a single monitor well is available, but in principle the full moment tensor can be extracted for multiple monitor wells. The primary information derived consists of the slippage-plane orientation, the slip direction, and the moment (strength) of the event. Presumably, these slippages occur on existing planes of weakness, such as natural fractures, bedding planes, or potentially even fracture planes induced by the hydraulic fracture, thus providing information about the reservoir and the process. An approach for performing the moment-tensor inversion is discussed for both single and multiple monitor wells, along with methods to estimate various parameters. Both synthetic and field examples are provided to demonstrate what can be extracted from the data set under various conditions.
Simulation of Flow and Dispersion on Pore-Space Images
Authors: Mostaghimi Peyman , Bijeljic Branko , Blunt Martin J. 
Published: February 2011

Abstract
We simulate flow and transport directly on pore-space images obtained by micro-CT scanning of rock cores. An efficient Stokes solver is used to simulate low-Reynolds number flows. The flow simulator uses a finite-difference method along with a standard predictor-corrector procedure to decouple pressure and velocity. An algebraic multigrid technique solves the linear systems of equations. We then predict permeability and the results are compared with lattice Boltzmann numerical results and available experimental data.
For solute transport we apply a streamline-based algorithm that is similar to the Pollock algorithm common in field-scale reservoir simulation, but which employs a novel semi-analytic formulation near solid boundaries to capture, with sub-grid resolution, the variation in velocity near the grains. A random walk method accounts for molecular diffusion. The streamline- based algorithm is validated by comparison with published results for Taylor-Aris dispersion in a single capillary with a square cross-section. We then accurately predict available experimental data in the literature for longitudinal dispersion coefficient as a function of Peclet number. We introduce a characteristic length based on ratio of volume to pore/grain surface area that can be used for consolidated porous media to calculate Peclet number.
Application of Particle Swarms for History Matching in the Brugge Reservoir
Authors: Mohamed Linah , Christie Mike , Demyanov Vasily , Robert Emmanuel , Kachuma Dick 
Published: February 2011

Abstract
Reservoir modelling is frequently used in the oil industry to measure the risk associated with alternative production scenarios. However, reservoir models themselves contain a high level of uncertainty because of the typically very limited, sparse and multi-scaled reservoir knowledge. The effect of this uncertainty can be assessed by producing a set of diverse models that match the production data reasonably well and using these models to quantify uncertainty in predicting the future performance of the reservoir.
Evolutionary and swarm intelligence algorithms have become very popular for history matching due to their simplicity and parallel implementation capacity. This paper focuses on the application of Particle Swarm Optimisation (PSO) for history matching the Brugge field (a recent SPE benchmark case study). The parameterisation of the model is based on principal component analysis (PCA) for modelling spatially correlated random fields (e.g. porosity, net-to-gross and permeability) applied to the set of initial realisations which describe the range of prior beliefs. The PSO is then used to find the set of possible combinations of parameters, represented by the PCA eigenvalues, which match the historical data and honour the static data from the wells present in the initial realisations.
We show that PSO is able to find multiple good and diverse history matched models for the Brugge reservoir without exhaustive sampling of the parameter space. Uncertainty of production forecasts are quantified by P10-P50-P90 uncertainty envelope obtained from the ensemble of PSO models. The history matching results are compared with the ones obtained with Ensemble Kalman Filter data assimilation method. These results show the ability of PSO to handle large history matching problems and obtain results comparable to the EnKF for this case study.
Advances in Openhole Packer/Sleeve Completions Coupled With Multilaterals Provide Cost-Effective Solutions
Authors: Johnson C. Christopher , Courrege David W. 
Published: February 2011

Abstract
The Bakken Shale located in North Dakota has seen large increases in oil and gas production. The contributing technologies that have aided in the increased production are the recent advances in openhole packer and sleeve completions. These completions have enabled operators to isolate and fracture up to 24 stages using a one-trip openhole packer and sleeve completion.
The use of multilaterals enables operators to save capital investment by accessing production from two laterals while chilling a single vertical wellbore. Greater drainage access across a section is also achieved by using this technology. Coupling multilateral and openhole packer/sleeve technologies together allows for multiple-stage hydraulic fracturing operations of both laterals.
This paper will show how employing openhole packer and sleeve completions coupled with a fracturable multilateral junction provides a cost-effective way to drill, complete, and stimulate wells in the Bakken. The experience gamed in the Bakken will be applicable worldwide as operators look to optimize openhole completions in their unconventional reservoirs.