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Tabatabaei M.,Marathon Oil | Ghalambor A.,Oil States International | Guo B.,University of Louisiana at Lafayette
SPE Production and Operations | Year: 2012

Optimizing the completion interval to minimize water coning has been long recognized as a challenge in the industry. After reviewing the mechanism of water coning, a simple analytical model is presented in this study for water-coning systems in high-conductivity reservoirs (reservoirs with low pressure gradient). This model is applicable to predict the critical rate and to determine the optimum wellbore penetration for achieving maximum water-free production rate of vertical oil wells. The developed model predicts the critical rate on the basis of a radial/spherical/combined (RSC) 3D flow field assumption that takes into account the effect of permeability anisotropy, density difference between water and oil, and limited wellbore penetration. Moreover, optimum wellbore penetration into the oil zone has been determined by maximizing the critical rate. This analytical model reveals the optimum wellbore penetration in high-conductivity reservoirs to be almost half of the pay-zone thickness, depending on the radius of wellbore and drainage area, pay-zone thickness, and the permeability anisotropy of the reservoir. Copyright © 2012 Society of Petroleum Engineers. Source

Evans E.,Schlumberger | Ghalambor A.,Oil States International | Orangi A.,Hess
Proceedings - SPE International Symposium on Formation Damage Control | Year: 2016

Horizontal wells with multistage hydraulic fractures have become the most common practice to obtain viable commercial production from shale and tight gas reservoirs. With a marked increase of gas production emerging from these tight reservoirs, it is necessary to further study the effects of formation damage due to condensate dropout and how best to prevent and mitigate this damage. There are two common ways to mitigate and treat condensate banking. The first method is to fracture the existing well. This allows bypassing the condensate and therefore increasing well productivity. The second method is to shut-in the well and allow pressure to build up so that the dropped out liquids are revaporized back into the gas. These options, respectively, involve large capital expenses and temporary decrease of production. Before deploying these solutions, the condensate dropout damage can be strongly reduced at no (field) cost by optimizing the well location. This objective in this study was to determine the optimum well location to mitigate formation damage due to condensate dropout in a tight gas well. Compositional reservoir simulations were conducted with different condensate gas ratios and relative permeability curves to quantify the loss of productivity due to formation damage under different conditions. The target formation was 100 ft thick, and a tartan grid was used to represent the hydraulic fractures within the tight gas well. This study determined that well placement plays a key role in preventing damage due to condensate banking. The optimized placement of the well can drastically enhance the viability of a project by allowing for a larger recovery. Copyright 2016, Society of Petroleum Engineers. Source

Mahmoudi M.,University of Alberta | Roostaei M.,University of Alberta | Ghalambor A.,Oil States International
Proceedings - SPE International Symposium on Formation Damage Control | Year: 2016

The primary goal of screen design for steam assisted gravity drainage (SAGD) operations is to prevent the entrance of the poorly or unconsolidated sand into the production flow stream, which could cause serious damages to the downhole/surface facilities. Current screen design approach fits one screen opening size for the entire length of the well, which leads to a conservative screen opening to avoid sand production along the well. This study introduces a new approach to design the screen opening, considering different opening sizes along the horizontal well. The proposed workflow in designing the optimum screen opening relies on well logs and core analysis to map the grain size distribution within reservoir through a geostatistical approach. Considering the horizontal well path and the changes in liner length due to installation and thermal loads, we design the screen aperture size to optimize the screen selection based on sand facies present in different sections of the wellbore. This enables us to provide different screen opening for different sand facies along the horizontal well. The new approach provides a more detailed design for screen opening for the horizontal well according to the sand size distribution within the reservoir instead of trying to fit one opening size for the entire horizontal section. It also considers the thermal expansion of the joints. This approach designs the screen opening for different sand facies along the horizontal well in a way which obtains the highest productivity and lowest produced sand. This paper provides a novel workflow for the design and optimization of screen for horizontal wells, which could be used to optimize the design of different standalone screens such as slotted liner, precise punch screen (PPS) and wire wrapped screen (WWS). Copyright 2016, Society of Petroleum Engineers. Source

Toutain P.,Oil States International
Society of Petroleum Engineers - SPE International Conference on Health, Safety and Environment 2014: The Journey Continues | Year: 2014

Resources other than those immediately available to an operator (either owned, under contract or through third parties such as oil spill organisations) may be required to respond to a large scale offshore incident. Such supplementary resources may be owned or under contract to other operators in or near the affected basin. While the exploration & production industry has demonstrated that it can cooperate rapidly and effectively in response to such incidents, it is OOP)s belief that a framework to guide the consideration of mutual aid and response assistance can further improve the industry)s ability to respond. OGP looked at the typical elements of a response to a large-scale offshore incident and concluded that it is at the local, regional or basin level that operators are more likely to face common logistical, technical, legal, regulatory environment as well as being able to quickly access resources. Therefore, the framework was developed to aid operators and industry associations in initiating and conducting mutual aid discussions at this level. This paper describes the framework in broad terms, going through the role of mutual aid in the response to offshore incidents, it lists the (Guiding principles of mutual aid) and lays out a process for scoping-through the identification of needs and opportunities for mutual aid-and developing arrangements from the opportunities identified. It concludes by describing issues that may need to be addressed when considering mutual aid arrangements and outlining some practical measures that may help to enhance the functioning and maintenance of mutual aid arrangements. Copyright 2014 , Society of Petroleum Engineers. Source

Izadi M.,Colorado School of Mines | Ghalambor A.,Oil States International
SPE Reservoir Evaluation and Engineering | Year: 2013

Building an integrated subsurface model is one of the main goals of major oil and gas operators to guide the field-development plans. All field-data acquisitions from seismic, well logging, production, and geomechanical monitoring to enhanced-oil-recovery (EOR) operations can be affected by the accurate details incorporated in the subsurface model. Therefore, building a realistic integrated subsurface model of the field and associated operations is essential for a successful implementation of such projects. Furthermore, using a more reliable model can, in turn, provide the basis in the decision-making process for control and remediation of formation damage. One of the key identifiers of the subsurface model is accurately predicting the hydraulic-flow units (HFUs). There are several models currently used in the prediction of these units on the basis of the type of data available. The predictions that used these models differ significantly because of the assumptions made in the derivations. Most of these assumptions do not adequately reflect realistic subsurface conditions, thus increasing the need for better models. A new approach has been developed in this study for predicting the petrophysical properties and improving the reservoir characterization. The Poiseuille flow equation and Darcy equation were coupled, taking into consideration the irreducible water saturation in the pore network. The porous medium was introduced as a domain containing a bundle of tortuous capillary tubes with irreducible water lining the pore wall. A series of routine and special core analysis was performed on 17 Berea sandstone samples, and the petrophysical properties were measured and X-ray diffraction (XRD) analysis was conducted. In building the petrophysical model, it was initially necessary to assume an ideal reservoir with 17 different layers, each layer representing one Berea sample. Afterward, by the iteration and calibration of the laboratory data, the number of HFUs was determined by use of the common HFU model and the proposed model accordingly. A comparative study shows that the new model provides a better distribution of HFUs and prediction of the petrophysical properties. The new model provides a better match with the experimental data collected than the models currently used in the prediction of such parameters. The good agreement observed for the Berea sandstone experimental data and the model predictions by use of the new permeability model shows a wider range of applicability for various reservoir conditions. In addition, the model has been applied to a series of core-analysis data on lowpermeability Medina sandstone, Appalachian basin, northwest Pennsylvania. The flow-unit distribution by use of the proposed model shows a better flow-zone distinction, and the permeability/porosity relationship has a higher confidence coefficient. Copyright © 2013 Society of Petroleum Engineers. Source

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