bluuebunny/crossref_metadata_2025_split huggingface dataset:
Aquifer Management To Accelerate CO2 Dissolution and Trapping
Authors: Anchliya A.. , Ehlig-Economides C.. , Jafarpour B.. 
Published: November 2012

Summary
Bulk-phase CO2 injection into saline aquifers can provide substantive reduction in CO2 emissions if the risk arising from aquifer pressurization is addressed adequately through mechanisms such as brine production out of the system (Anchliya 2009). While this approach addresses the risks associated with aquifer pressurization it does not address the problem of ensuring CO2 trapping as an immobile phase and its accumulation at the top of the aquifer. The performance of bulk-CO2-injection schemes highly depends on the seal-integrity assessment and presence of thief zones. The accumulated pocket of free CO2 can readily leak through a breach in the aquifer seal. Ideally, the aquifer should be monitored as long as the free CO2 is present, but if the CO2 is not immobilized, it is expected to remain underneath the seal rock for more than 1,000 years. Therefore, long-term monitoring of the seal integrity and avoiding leakage will be very costly.
To minimize the free CO2 below the caprock, we propose an engineered system to reduce aquifer pressurization and accelerate CO2 dissolution and trapping. We achieve these objectives through effective placement of brine injection and production wells to facilitate the lateral movement (hence, residual and solubility trapping) of CO2 in the aquifer and impede its upward movement. The simulation results for example engineered well configurations in this paper suggest that substantial improvements in immobilizing CO2 can be achieved through increasing enhanced solubility and residual trapping that result from better CO2-injection sweep efficiency. This approach has the potential to greatly reduce the risk of CO2 leakage both during and after injection. The controlled injection of CO2 with this technique reduces the uncertainty about the long-term fate of the injected CO2, prevents CO2 from migrating toward potential outlets or sensitive areas, and increases the volume of CO2 that can be stored in a closed aquifer volume during the CO2-injection period. Field-scale compositional simulation cases are discussed, and sensitivity studies are used to provide guidelines for well spacing and flow rates depending on aquifer properties and the volume of CO2 to be stored. Although it requires additional drilled wells, the active engineered configuration proposed for CO2 injection significantly reduces the reservoir volume required to effectively sequester a given volume of CO2, and the increase in the cost caused by additional wells is recovered by dramatic reduction in monitoring cost.
Hole-Cleaning Performance of Gasified Drilling Fluids in Horizontal Well Sections
Authors: Ozbayoglu E.M.. M. , Osgouei R.E.. E. , Ozbayoglu A.M.. M. , Yuksel E.. 
Published: November 2012

Summary
This study aims to investigate the hole-cleaning process during the flow of a drilling fluid consisting of a gas and a liquid phase through a horizontal annulus. Experiments have been conducted using the Middle East Technical University (METU) multiphase flow loop under a wide range of air- and water-flow rates while introducing cuttings into the annulus for different amounts. Data have been collected for steady-state conditions (i.e., liquid, gas, and cuttings injection rates are stabilized). Collected data include flow rates of liquid and gas phases, frictional pressure drop inside the test section, local pressures at different locations in the flow loop, and high-speed digital images for identification of solid, liquid, and gas distribution inside the wellbore. Digital imageprocessing techniques are applied on the recorded images for volumetric phase distribution inside the test section, which are in dynamic condition. The effects of liquid and gas phases are investigated on cuttings-transport behavior under different flow conditions. Observations showed that the major contribution for carrying the cuttings along the wellbore is the liquid phase. However, as the gas-flow rate is increased, the flow area left for the liquid phase dramatically decreases, which leads to an increase in the local velocity of the liquid phase causing the cuttings to be dragged and moved, or a significant erosion on the cuttings bed. Therefore, increase in the flow rate of gas phase causes an improvement in the cuttings transport although the liquid-phase flow rate is kept constant. On the basis of the experimental observations, a mechanistic model that estimates the total cuttings concentration and frictional pressure loss inside the wellbore is introduced for gasified fluids flowing through a horizontal annulus. The model estimations are in good agreement with the measurements obtained from the experiments. By using the model, minimum liquid- and gas-flow rates can be identified for having an acceptable cuttings concentration inside the wellbore as well as a preferably low frictional pressure drop. Thus, the information obtained from this study is applicable to any underbalanced drilling operation conducted with gas/liquid mixtures, for optimization of flow rates for liquid and gas phases to transport the cuttings in the horizontal sections in an effective way with a reasonably low frictional pressure loss.
Sand on Demand: A Laboratory Investigation on Improving Productivity in Horizontal Wells Under Heavy-Oil Primary Production—Part II
Authors: Meza-Díaz Brigida , Sawatzky Ron , Kuru Ergun 
Published: November 2012

Summary
The cold-production-recovery process, also known as cold heavy-oil production with sand (CHOPS), is a method for enhancing primary heavy-oil production by aggressively producing sand. It is successful in vertical (or slanted or deviated) wells in western Canada. In this process, large amounts of sand are produced on a continuing basis along with heavy oil. Attempts at cold production in horizontal wells have not been particularly successful. When sand production has been generated in horizontal wells, these wells have tended to become plugged with sand.
This paper presents the results of experiments performed to assess the feasibility of applying cold heavy-oil production in horizontal wells that have been completed with slotted liners using less-aggressive (i.e., managed) sand-production strategies. Specifically, the effects of slot size, confining stress, fluid velocity, and sand-grain sorting on sand production were investigated.
The results indicate that slot-size selection is critical for establishing "sand on demand." From the experiments, a correlation between slot size and controlled sand production was found for well-sorted sands. This correlation should allow for the specification of appropriate slot sizes for target reservoirs containing well-sorted sands.
In the experiments, when flow rates resulted in low but persistent sand production, channels and/or elliptical dilated zones were created that greatly enhanced the effective permeability near the slot. This observation suggests that producing at low and steady sand cuts for a long period of time might bring two benefits: a way to transport the sand out of the well without causing plugging and the creation of high-permeability channels or zones that can improve production from the reservoir.
To summarize, if the appropriate slot size were combined with the right drawdown rates, controlled sand production could be achieved, with attendant significant increases in permeability. This suggests that substantially increased oil-production rates could be achieved from horizontal wells if sand-production rates could be maintained at low but persistent levels.
An Improved Adjoint-Sensitivity Computation for Multiphase Flow Using Wavelets
Authors: Awotunde A.A.. A. , Horne R.N.. N. 
Published: November 2012

Summary
In history matching, one of the challenges in the use of gradient-based Newton algorithms (e.g., Gauss-Newton and Leven-berg-Marquardt) in solving the inverse problem is the huge cost associated with the computation of the sensitivity matrix. Although the Newton type of algorithm gives faster convergence than most other gradient-based inverse solution algorithms, its use is limited to small- and medium-scale problems in which the sensitivity coefficients are easily and quickly computed. Modelers often use less-efficient algorithms (e.g., conjugate-gradient and quasi-Newton) to model large-scale problems because these algorithms avoid the direct computation of sensitivity coefficients. To find a direction of descent, such algorithms often use less-precise curvature information that would be contained in the gradient of the objective function. Using a sensitivity matrix gives more-complete information about the curvature of the function; however, this comes with a significant computational cost for large-scale problems.
An improved adjoint-sensitivity computation is presented for time-dependent partial-differential equations describing multiphase flow in hydrocarbon reservoirs. The method combines the wavelet parameterization of data space with adjoint-sensitivity formulation to reduce the cost of computing sensitivities. This reduction in cost is achieved by reducing the size of the linear system of equations that are typically solved to obtain the sensitivities. This cost-saving technique makes solving an inverse problem with algorithms (e.g., Levenberg-Marquardt and Gauss-Newton) viable for large multiphase-flow history-matching problems. The effectiveness of this approach is demonstrated for two numerical examples involving multiphase flow in a reservoir with several production and injection wells.
Casing While Drilling (CwD): A New Approach To Drilling Fiqa Formation in the Sultanate of Oman—A Success Story
Authors: Sánchez F.. , Houqani S.. , Turki M.. , Cruz M.. 
Published: November 2012

SummaryHighly reactive Fiqa shale used to compel well engineers in the Sultanate of Oman to plan drilling phase of surface and intermediate sections primarily based on time exposure to aqueous drilling fluid water-based mud (WBM). The new approach of drilling the time-dependent Fiqa formation using casing-while-drilling (CwD) allows well engineers to plan prospective top/intermediate wellbore sections differently by enhancing the overall drilling performance. This reduces the risk of setting casing strings at unplanned depths, getting pipe stuck, or reaming continuously when drilling with conventional drillstring. The technical feasibility study, risk assessment, planning, execution, and the lessons learned during the process of drilling two top-section pilot projects are described in this document. The CwD team compares the drilling performance of several offset wells and suggests actions to improve the CwD technology in Oman.Two 17½ - and 22-in. surface sections were drilled successfully with large-diameter casing strings and reached 754- and 894-m measured depths, respectively. The implementation of the CwD concept reduced the overall drill/case phase time up to 40%, in comparison with the average using conventional drilling in those fields. Exposure time of Fiqa to aqueous environment was reduced by eliminating conditioning trips and nonproductive-time (NPT) associated with wellbore instability. Drilling both sections with non-retrievable 17½×13⅜-in. and 22×18⅝ -in. CwD systems did not require modification of well design or rig. The optimization of this technology will support its implementation as the conventional drilling approach in some fields in Oman.
Injection Profiling During Limited-Entry Fracturing Using Distributed-Temperature-Sensor Data
Authors: Hoang Hai , Mahadevan Jagannathan , Lopez Henry 
Published: November 2012

Summary
Tight gas plays often have multiple lenses of producing formations. Multizone fracturing or limited-entry fracturing is a cost-effective method to complete and produce tight gas wells in these layered reservoirs. The rate and volume of fracturing fluid injected into the different layers have an important role in determining the fracture characteristics. However, because of the spatial restriction of downhole conditions, it is very challenging to obtain a specific injection rate for each perforated zone. Temperature variations in the wellbore, outside of the casing, are available with new technology such as distributed-temperaturesensor (DTS) fiber-optic cables. The main objective of this study is to relate the wellbore-temperature changes as measured by DTS data to the wellbore and fractured-interval injection rates during a multizone fracturing process.
We develop a forward simulation model on the basis of mass and energy conservation for calculating the temperature profile and temperature history in the wellbore and in the rock surrounding the wellbore. The model allows for liquid flow into the fractured interval. Subsequently, the model is integrated with an inverse-estimation algorithm, which is used to estimate flow rates both in the wellbore and into the fractured interval. The estimation algorithm is based on a gradient search method. A distinguishing feature of this work is the development of a radial model used to represent the temperature evolution in the near-wellbore region. The higher order allows accurate calculation of the temperature in the wellbore while still capturing the fluid-flow and heat-transport aspects of the hydraulic-fracture propagation.
Our estimation results show a good comparison between the calculated temperature profiles and those observed in the field with DTS. Also, the model is able to estimate a flow-rate history consistent with total field-injection volume. This work enables an accurate and quick interpretation of the wellbore DTS data to determine the interval injection rates during a hydraulic-fracturing process. Knowledge of accurate interval injection rates and the corresponding fracture characteristics can be useful in designing a better limited-entry completion that can optimize the fracture length by use of rate control and/or fluid diversion.
Robust Constrained Optimization of Short- and Long-Term Net Present Value for Closed-Loop Reservoir Management
Authors: Chen C. , Li G. , Reynolds A. C. 
Published: November 2012

Summary
In this paper, we develop an efficient algorithm for production optimization under linear and nonlinear constraints and an uncertain reservoir description. The linear and nonlinear constraints are incorporated into the objective function using the augmented Lagrangian method, and the bound constraints are enforced using a gradient-projection trust-region method. Robust long-term optimization maximizes the expected life-cycle net present value (NPV) over a set of geological models, which represent the uncertainty in reservoir description. Because the life-cycle optimal controls may be in conflict with the operator's objective of maximizing short-time production, the method is adapted to maximize the expectation of short-term NPV over the next 1 or 2 years subject to the constraint that the life-cycle NPV will not be substantially decreased. The technique is applied to synthetic reservoir problems to demonstrate its efficiency and robustness. Experiments show that the field cannot always achieve the optimal NPV using the optimal well controls obtained on the basis of a single but uncertain reservoir model, whereas the application of robust optimization reduces this risk significantly. Experimental results also show that robust sequential optimization on each short-term period is not able to achieve an expected life-cycle NPV as high as that obtained with robust long-term optimization.
A Multiscale Workflow for History Matching in Structured and Unstructured Grid Geometries
Authors: Bhark E.. , Rey A.. , Datta-Gupta A.. , Jafarpour B.. 
Published: November 2012

SummaryWe present the development and field application of a workflow for multiscale reservoir-model calibration that seamlessly integrates production data into the reservoir description from the facies to the grid-cell scale. To start with, the permeability field is parameterized using a novel grid-connectivity-based transformation basis that can be applied with any model geometry, including unstructured and corner-point grids. The parameterization basis functions emerge from spectral decomposition of the grid-connectivity Laplacian and are related to the structural harmonics of the grid. To reconcile data with model resolution during history matching, we first use the coarsest-scale basis functions to identify the large-scale variability. Additional smaller-scale basis elements are then adaptively incorporated to successively refine the model to a level supported by data resolution. During refinement, the inclusion of more detailed basis functions into the parameterization is determined by generic modal frequency when the prior model is unavailable or by using prior information when available. In the final step of the workflow, a streamline-based inversion is performed to locally adjust the reservoir model at grid-cell resolution along preferential-flow paths defined during the coarser-scale parameterization.We demonstrate the suitability and effectiveness of the developed workflow through application to an offshore turbidite reservoir with frequent well intervention, including shut-ins and recompletions. The static model has over 300,000 cells, a complex channelized interpretation with faults, four injector/producer pairs with deviated wells, and over eight years of production history, including water cut and pressure data. The grid-connectivity-based parameterization effectively updates the prior regional permeability at scales and in locations warranted by the data, while preserving the geologic continuity and avoiding ad hoc redefinition of regions given the sparse well pattern. The multiscale calibrated-permeability field indicates flow communication previously unrecognized in static geologic interpretation or manual history matching.
Development of a Transient Mechanistic Two-Phase Flow Model for Wellbores
Authors: Shirdel Mahdy , Sepehrnoori Kamy 
Published: November 2012

SummaryA great deal of research has been focused on transient two-phase flow in wellbores. However, there is lack of a comprehensive two-fluid model in the literature. In this paper, we present an implementation of a pseudo-compositional, thermal, fully implicit, transient two-fluid model for two-phase flow in wellbores. In this model, we solve gas/liquid mass balance, gas/liquid momentum balance, and two-phase energy balance equations to obtain five primary variables: liquid velocity, gas velocity, pressure, holdup, and temperature. This simulator can be used as a stand-alone code or can be used in conjunction with a reservoir simulator to mimic wellbore/reservoir dynamic interactions. In our model, we consider stratified, bubbly, intermittent, and annular flow regimes using appropriate closure relations for interphase and wall-shear stress terms in the momentum equations. In our simulation, we found that the interphase and wall-shear stress terms for different flow regimes can significantly affect the model's results. In addition, the interphase momentum transfer terms mainly influence the holdup value.The outcome of this research leads to a more accurate simulation of multiphase flow in the wellbore and pipes, which can be applied to the surface facility design, well-performance optimization, and wellbore damage estimation.
A New Analytical Method for Analyzing Linear Flow in Tight/Shale Gas Reservoirs: Constant-Flowing-Pressure Boundary Condition
Authors: Nobakht Morteza , Clarkson C.R.. R. 
Published: November 2012

Summary
Many tight/shale gas wells exhibit linear flow, which can last for several years. Linear flow can be analyzed using a square-root-of-time plot, a plot of rate-normalized pressure vs. the square root of time. Linear flow appears as a straight line on this plot, and the slope of this line can be used to calculate the product of fracture half-length and the square root of permeability.
In this paper, linear flow from a fractured well in a tight/shale gas reservoir under a constant-flowing-pressure constraint is studied. It is shown that the slope of the square-root-of-time plot results in an overestimation of fracture half-length, if permeability is known. The degree of this overestimation is influenced by initial pressure, flowing pressure, and formation compressibility. An analytical method is presented to correct the slope of the square-root-of-time plot to improve the overestimation of fracture halflength. The method is validated using a number of numerically simulated cases. As expected, the square-root-of-time plots for these simulated cases appear as a straight line during linear flow for constant flowing pressure. It is found that the newly developed analytical method results in a more reliable estimate of fracture half-length, if permeability is known. Our approach, which is fully analytical, results in an improvement in linear-flow analysis over previously presented methods. Finally, the application of this method to multifractured horizontal wells is discussed and the method is applied to three field examples.
Acidizing-Induced Damage in Sandstone Injector Wells: Laboratory Testing and a Case History
Authors: Al-Mohammad A.M.. M. , Alkhaldi M.H.. H. , Al-Mutairi S.H.. H. , Al-Zahrani A.A.. A. 
Published: November 2012

Summary
Throughout a well's lifetime, formation damage can occur during the activities of drilling, completion, injection, or well-stimulation treatments. Typically, remedial treatments to restore the well performance involve injection of reactive fluids capable of removing such damage. Therefore, understanding damage mechanism and type is critical for fluid selection and effective treatment design. Without this knowledge, the conducted stimulation treatment could cause a more-severe form of formation damage.
This report discusses the improper use of mud acid [at 9 wt% hydrochloric acid (HCl)/1 wt% hydrofluoric acid (HF)] in restoring the injectivity of Well N-510. The subject well was stimulated with two acid-stimulation treatments in an attempt to improve the poor results of a previous cleanout job, conducted to remove mud filter cake. These treatments were designed to remove the damage that has been limiting the well injectivity. However, it was found that these acidizing treatments created a new formation damage that resulted in the severe decline of well injectivity.
Integration of chemical-analysis techniques performed on return fluids and coreflood experiments was used to assess the effectiveness of all conducted treatments. This report demonstrates the techniques used to identify the source and type of formation-damage mechanism that occurred during each treatment. On the basis of these studies, it was found that the poor results of the cleanout job were caused by precipitation of calcium sulfate. This precipitation was a result of the mixing between spent cleanout acid, having a high amount of calcium, and the high-sulfate-content water. Most of this precipitation occurred in the wellbore vicinity during the preceding stages of the well flowback.
Calcium sulfate precipitation had a negative impact on the performance of the conducted acid-stimulation treatments. In the presence of this precipitation, the two successive mud-acid-stimulation treatments created another form of damage (i.e., in-situ fluoride-based scale). Initially, the fresh injected mud acid dissolved most of the calcium sulfate scale, and as a result, it contained a high amount of dissolved calcium ions. However, upon the spending of injected mud acid in the formation, calcium fluoride precipitated as a result of the increase of solution pH value.
The interactions between different acid systems and the constituents of the downhole environment, resulting in the precipitation of calcium sulfate and calcium fluoride, are discussed. In addition, this report provides recommended modifications for future stimulation treatments, conducted under similar conditions, so as to prevent the formation of these scales.