bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Generic Model for Optimizing the Selection of Artificial Lift Methods for Liquid Loaded Gas Wells
Authors: Rehman A. , Soponsakulkaew N. , Bello O. , Falcone G. 
Published: October 2011

ABSTRACT
An increasing number of gas wells worldwide produce at rates below their maximum potential due to liquid loading, which occurs when the gas velocity in the well falls below a critical value, at which point the liquid that was previously carried upward by the gas begins to fall back. The liquid accumulates down hole, where it increases the hydrostatic back-pressure on the reservoir, destabilizes the multiphase flow in the well, decreases gas production rate, in severe cases, can kill the well.
There are a number of tools, techniques and processes that are currently used in the industry to mitigate the impact of liquid loading. Choosing the optimum artificial lift solution for a specific occurrence of loading in the field is a very challenging task that requires an integrated, multi-disciplinary approach to deliver the highest possible value for the asset.
The objective of this paper is to develop a quantitative method which couples integrated production simulations, economic analysis and a distance-based optimization model to streamline and improve the selection of the most appropriate lifting option for given well conditions, while considering multiple factors impacting on the decision making process.
The production system is modeled with a widely available commercial software package. The feasibility of using integrated production modeling in conjunction with a distance-based optimization methodology is demonstrated with two synthetic case studies representing a high-rate and a low-rate gas well.
The results show that the proposed methodology can help optimize the selection of artificial lift solutions for liquid loaded gas wells.
A Multimodal 3D Imaging Study of Natural Gas Flow in Tight Sands
Authors: Silin Dmitriy , Kneafsey Timothy J. , Ajo-Franklin Jonathan B. , Nico Peter 
Published: October 2011

Abstract
Pore scale phenomena, especially in multi-phase flow, have a strong impact on the mechanisms and efficiency of gas recovery. We studied the impact of the pore space geometry on single- and two-phase flow properties of tight-sands. X-ray computed tomography (CT) and scanning-electron microscopy (SEM), along with other imaging tools provide insights into pore structure at multiple scales. Segmented micron-scale resolution CT 3D images were used as input data for simulations based on the Maximal Inscribes Spheres (MIS) method. Finite-difference flow simulations of creeping flow on MIS-evaluated equilibrium fluid distribution predict of the relative permeability curves as functions of saturation. A pore-scale model of two-phase gas flow accounts for condensate dropout based on thermodynamic equilibrium. The pore-scale analysis results are applied in optimal-control model of wet gas flow with liquid skin.
This study leads to the following conclusions: (a) the estimated minimal wetting fluid threshold saturation, at which the gas phase is disconnected, is much lower than that for conventional sandstones; (b) pore-scale flow simulations suggest that in imbibition, the gas and brine (or other wetting fluid) can block the other phase's flow ("Permeability Jail"), where the blockage of gas is of capillary nature, and the blockage of liquid phase is dynamic; (c) pore-scale simulations of drainage do not show mutual blockage of the fluids; (d) the rate of the local condensate dropout is proportional to the dot product of the local flow velocity and pressure gradient; (e) upscaling of conclusion (d) to Darcy scale leads to condensate dropout rate proportional to the pressure gradient; (f) the optimal-control model suggests that gas well production-rate control may have potential for considerably increasing the total gas recovery.
Conversion of Cyclic Steam Injection to Continous Steam Injection
Authors: Alikhlalov K. , Dindoruk B. 
Published: October 2011

Abstract
Estimated total world in-place oil volumes are between 9 trillion and 13 trillion barrels, of which 30% is conventional crude. The rest is 30% oil sands and bitumen, 25% is "extra heavy" oil and 15% is "heavy" oil. Normally definition of heavy oil is based on gas free properties of the oil. An oil is classified as heavy oil if the dead oil viscosities are between 100 centipoises to 10000 cp at reservoir temperatures with API's between 10 to 20. Extra-heavy oil is commonly defined as oil having a gravity of less than 10° and a reservoir viscosity more than 10 000 centipoises. When reservoir viscosity measurements are not available, extra-heavy oil is considered to have a lower limit of 4° API (WPC Report - 2007). Though industry has known about heavy oils for a century, it still provides a minute fraction of the world's production. Because in many cases oil will not flow at economical rates (mainly due to high viscosities). One of the most important technical challenges for Enhanced Oil Recovery (EOR) engineers is to develop an economical and feasible recovery process for heavy oil reservoirs.
Depending on the reservoir-fluid system, commercial rates can be achieved by injecting (heat) steam. However, injectivity can be one of the key factors that can lead to difficulties to deliver enough heat to contact significant portion of the reservoir with steam (or for any other potential injectant). The main reason for such low injectivities in targeted heavy oil reservoirs originates from the excessively high in-situ oil viscosities. In order to facilitate the injection of reasonable quantities of steam in a continuous manner, cyclic steam injection techniques are often utilized at early stages of such projects, especially for extra heavy oil reservoirs. From the full project time cycle point of view, a combination of cyclic and continuous steam injection could be used to overcome this problem. In this paper, we have considered a five-spot pattern and studied optimum time for the conversion of cyclic steam injection to continuous steam injection for various type of reservoir and fluid properties using a commercial numerical simulator (STARS, 2009). To our knowledge, this is the first study that addresses the cyclic to contuinuous steam injection conversion time and correlates it to simple measurable quantities for the benchmark system with the reservoir/fluid properties selected.
Combined Temperature and Pressure Data Interpretation: Applications to Characterization of Near-Wellbore Reservoir Structures
Authors: Duru Obinna O. , Horne Roland N. 
Published: October 2011

Abstract
The models that describe distributed temperature behavior in a reservoir appear as advection-diffusion equations with forcing terms that include compressibility effects due to Joule-Thomson and adiabatic expansion. The model lends itself to solution techniques like Operator Splitting which decomposes a multiphysics, multiscale problem into components representing different simple physics and scales, where each component can be solved independently at each time step using any appropriate technique for the physical process.
Unlike diffusion, advection does not destroy information and it is nonsmoothing and preserves sharp boundaries. By Method of Characteristics (MOC), a process can be estimated as it is advected downstream, from an initial data line, along characteristic paths at some characteristic velocity. This idea has useful implications on what information is carried by the advection processes that occur in a reservoir, such as heat advection.
In this paper, the results of solving the temperature model by Operator Splitting are presented. This approach utilizes the fact that temperature signatures, generated by spatial pressure changes in the reservoir due to Joule-Thomson and adiabatic expansion effects, are transported downstream in time from the initial line of generation to the wells. Along the corresponding characteristic curves, this transport is described by the characteristic velocity, and time to reach the well. Importantly these curves are independent of the pressure model but are dependent on the convective thermal velocity. The result is that reservoir structures that generate significant spatial pressure changes produce temperature signatures that are transported along the characteristic solution lines from the point of generation to the wells. Back calculations using the arrival times and and corresponding velocities give the location of the reservoir structures.
This technique was applied to the calculation of damaged radius, stimulated radius and inner boundaries of a multiring reservoir system, using temperature measurements and showed that near wellbore properties that are masked by wellbore storage in pressure transient analysis can be revealed by the slower moving temperature field. A proposal for new well test design to utilize this approach is also presented.
Gel Flooding Pilot Test and Evaluation Method Studies to Control Water Channeling in Conventional Heavy Oil Reservoir of Bohai Bay
Authors: Li Yanlai , Su Yanchun , Ma Kuiqian , Li Qizheng , Jia Xiaofei 
Published: October 2011

Abstract
LD oilfield was put online in Bohai Bay of China in 2005, characterized by huge thickness, high permeability, severe heterogeneity and high crude oil viscosity(210~460cp).Water injection in this oilfield was initiated in 2007. There are many challenges during water injection because high oil-water viscosity ratio leads quick breakthrough of injecting water, and high increasing rate of water cut, and so on.
In order to solve these problems, the gel flooding pilot test was conducted in LD oil field during the year 2009 to 2010. Before pilot test, laboratory study under field conditions was conducted to determine the chemical parameters of the gel injection. We also did numerical simulation study with CMG STARS. A range of variation of critical parameters was evaluated in the simulation for understanding the gelation process in the reservoir. The model was used to predict the reservoir response under different gel chemical parameters. Results from simulation showed that water cut reduced from 15.9 to 36.6% which matched the trends observed in wells. On other hand, dynamic method is also used to evaluate the gel pilot test. The Hall curve analysis was used to evaluate the effectiveness of the injection well and to calculate the resistance factor(RF) & residual resistance factor (RRF) (RF from 4.11 to 6.88, and RRF from 3.18 to 7.97 in LD oilfield). The decline curve analysis was used to obtain net incremental oil by gel injection treatment.
Results from two well patterns conducted gel pilot test in 2009 indicate that water cut reduction ranged from 3.2 to 36.8% and average oil production increases 14.7 m3/d. Based on results, another pilot test with two new well patterns were conducted in 2010 and we are now evaluating the new pilot test.
The pilot test & evaluation technology provides the foundation for promoting application of techniques to stabilize oil rate and control water production in reservoirs with conventional heavy oil in Bohai Bay of China.
Advanced Workflows For Joint Modelling Of Sedimentary Facies And Diagenetic Overprint, Impact On Reservoir Quality
Authors: Doligez B. , Hamon Y. , Barbier M. , Nader F. , Lerat O. , Beucher H. 
Published: October 2011

Abstract
The relationships between sedimentological facies and diagenetic properties differ depending on burial and geological history. In this paper we propose several examples where different quantitative expressions of diagenetic imprints lead to different workflows to be applied, to obtain final simulations reproducing both the sedimentary facies and the diagenetic trends in reservoir models.
A first case is based on an outcrop study of mixed siliciclastic-carbonate facies. The relationships between sedimentary facies and diagenesis have been used to define truncation rules for the plurigaussian algorithm, which aims at simulating both the distribution of sedimentary facies and the diagenetic overprint. Another workflow has been developed on this example, using the bi-plurigaussian simulation algorithm to address the problem of heterotopic bivariate conditional simulation (the two variables are known at different locations).
A second example is related to early diagenesis characterization. In this example (Madison Formation, Wyoming, USA), diagenetic imprints have been quantified, corresponding to a succession of diagenetic phases (micritization, calcite cementation, dolomitization...), that can coexist in the same sedimentary facies. The workflow using plurigaussian and nested simulation algorithms shows the impact of such joint simulations, as the diagenesis may completely modify the distribution of reservoir properties only based on a facies simulation.
In a third example, the modeled Aptian/Albian formation includes hydrothermal dolomites (HDT) associated to fractures and faults hosted in reefal and slope limestones. Simulations succeed in redistributing the HTD correctly at the surface and in the subsurface. Hence, in the deeper parts of the Aptian/Albian reefal rock unit, the dolomite is inherently associated to fractures, while at shallower levels, dolomitization seems to be more lateral, affecting probably more permeable facies. These results provide insights and numerical means for estimating volumes of dolomites (vertically and laterally) in an excellent case study of fracture-related HTD.
Diagenesis alters the original relationships between depositional facies and petrophysical properties in a reservoir. The quantitative integration of sedimentological facies and diagenetic properties is a key point to obtain a realistic geological model in reservoir studies.
The Design and Application Of Latest Generation Inflow Control Devices In Non-Horizontal Wells in the Bhagyam Field, India
Authors: McKenzie Tim , Wenk Andrew , Chavan Chetan , Kumar Sanjay , Khan Parvez , Garcia Gonzalo 
Published: October 2011

Abstract
Bhagyam is the second largest oilfield discovered to date in the Barmer Basin, India with more than 400mmb of viscous, waxy crude in place. This paper describes the evaluation, design and selection process for the use of the latest generation ICD in non-horizontal wells.
Sand face completions comprise sand screens coupled with an ICD. Inflow control was highly desirable due to the oil viscosity variation, high permeability, heterogeneity and adverse mobility ratio and the fact the completions could not be easily accessed below a PCP. Oil viscosity ranges from 14 to 250cp varying with depth. The variation in reservoir thickness, produced fluid viscosity and well productivity required a field adjustable pressure drop capability in the ICD. The ICD had to perform at high viscosity and needed to be tolerant to wax and sand production. The operator's experience in nearby fields observed the benefits of ICDs for providing efficient sand face cleanup in horizontal wells. It was vital to model this system accurately however there were significant challenges as no previous examples of using these devices in non-horizontal wells could be found and the ICD completion had not been modeled in a dynamic simulator for this scale of field development.
A dynamic simulation model which included the ICD completion was used to evaluate various completion options. A significant amount of work was performed to ensure the ICD was accurately modeled in the simulator. The simulations showed a long term benefit from using the ICD. To date 23 production wells have been drilled and of these 16 have been completed with the ICD screen systems.
This is one of the first applications of the latest generation ICD in non-horizontal wells particularly on a full field scale. It is also a case study of modeling the ICD completion with a dynamic simulator.
A New Approach to Deepwater Drilling Data Analysis Offers Enhanced Real Time Capabilities in a Post Macondo World
Authors: Greve John F. 
Published: October 2011

Abstract
Deepwater drilling activity in the Gulf of Mexico is no longer a given in the aftermath of the BP Macondo blowout. The new and ever evolving process to apply for drilling permits and operate now greatly depends on:
Optimal well designs certified for accuracy by Professional Engineers Thorough real-time monitoring of pertinent surface and down-hole data, and Deployment of new joint industry well capping and spill containment equipment for response to a blowout.
This paper makes no attempt to address the topics in items 1 and 3. In regard to item 2, a new method for loading and analyzing live time and depth data has shown merit during recent 2010 trials on two deepwater wells, one offshore eastern Canada and the other offshore west of the Shetland Islands. Rapid data access and standardized visualization of high resolution time, depth, and survey data is vital to insure that the occasional well control event doesn't become today's worldwide news headline. Deepwater drilling management demands a highly trained staff with timely access to data in a format easily used by the key decision makers wherever they are.
After the BP Macondo blowout, the news frenzy and blame game quickly showed the entire world that all operators may not be truly partnered with their rig and service suppliers in cooperative efforts to safely drill and complete the high rate wells which have historically made the deepwater Gulf of Mexico an attractive area to explore. After the blowout, the gathering of high quality data from remote real time data centers was quickly elevated to critical status for use in the government's investigation. High quality data collection and interpretation should always be managed with utmost attention to detail in light of the inherent risks of deepwater drilling and the fact that the industry simply cannot afford another incident.
After a major disaster in any business sector, new technology is always promoted as a key ingredient to avoid and manage any future accident. The oil industry must now meet the challenge of proving to the regulators charged with enforcement that our organizations have the capability for creating exacting pre-drill well plans, managing and prudently using real-time information. and responsibly responding to any well control event up to and including a blowout.
Statoil Experiences and Consequences Related to Continuous Chemical Injection
Authors: Olsen John Helge 
Published: October 2011

Abstract
Current completion solutions using Continuously Chemical Injection system faces challenges to prevent plugging of the capillary line. Where as Completion engineering principles have in the past mainly focused on the physical properties of the injection valve and mandrel, the chemists focus have been finding effective chemicals. We now experience that we need to have a system focus. The Chemical Injection Systems are not covered by any industry standards such as ISO or API, some elements are covered but none with focus on the entire system. As such Statoil has experienced that there are many other aspects and challenges linked to Chemical Injection systems that has not been explored in the past, and as a consequence Statoil has initiated an enhanced program to gain more knowledge and experience to better understand the physical and practical interlinks related to Continuous Chemical Injection.
Understanding the behaviour of chemicals in vacuum or near-vacuum pressure regimes in the upper part of the capillary line is one of the keys to understand the challenges related to these completions. Through communication with other operators throughout our industry, we understand that the challenges we have experienced are also relevant for others well operations. Statoil believe in an open environment where experiences are shared within the industry to improve our and others operations and to develop more robust solutions for the future.
Computational Analysis of Stress Interference Effect for Hydraulic Fracturing in Waste Injection Wells
Authors: Yao Yao , Lewandowski Jerome , Ellison Tim , Searles Kevin 
Published: October 2011

Abstract
Hydraulic fracturing is a key mechanism for injection into waste disposal wells. To successfully inject drill cuttings slurry or produced water under fracturing conditions and prevent unwanted migration, it is essential to predict the extent of hydraulic fractures accurately based on understanding the fundamental fracture mechanisms. Popular hydraulic fracture models for injection wells continue to rely on pseudo-3D fracture technology. However, when injection takes place in multiple, closely spaced wells, or under the influence of offset producers, stress interference effect on fracture geometry can hardly be predicted based on simple single-well methods. If the distance between the multiple injection wells is small such that pronounced stress perturbations exist, the stress interference could influence the fracture geometry and orientation. This paper presents a study on the stress interference effects on fracture orientation and spatial extent caused by multiple injection wells using a hybrid computational method incorporating finite element and boundary element fracture models. To investigate the stress interference effects, a pore pressure cohesive zone model was developed to predict hydraulic fracturing for injection wells through finite element analysis and sub-modeling technology. The model was applied to investigate the stress perturbation effect on fracture geometry caused by long-term, high-rate, multi-well waste injection into a heterogeneous geological environment. Boundary element analysis was performed to simulate the possible fracture reorientation and fracture merging caused by the changing of the stress field with the propagation of multiple hydraulic fractures. Injection wells with different well distances and stress boundary conditions were investigated. A 3D analytical tool has been developed to simulate the changes of stress due to the depletion in pore pressure from an offset location. The computational analysis on the stress field was verified with the analytical solution. Based on the finite element and boundary element analyses, revised stresses were incorporated into the tuned pseudo-3D models to update the hydraulic fracturing prediction to account for stress interference effects. Ultimately, the fracture predictions were quantified under the influence of stress interference.