bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experimental Evaluation of SAGD-ISC Hybrid Recovery Method
Authors: Oskouei S. J. , Maini B. , Moore R. G. , Mehta S. A. 
Published: February 2011

Abstract
Most of the current in-situ recovery methods have limitations which restrict their application in many heavy oil reservoirs. There are also a variety of undesirable environmental costs associated with the existing recovery techniques that limit their desirability. To overcome some of these issues, recent novel hybrid technologies have been proposed based on combining Steam Assisted Gravity Drainage and In Situ Combustion technologies. In the conventional ISC process, oil is displaced by an elevated temperature combustion zone but when the native oil mobility is not high enough this displacement becomes problematic. Warming up the reservoir and reducing the distance between injector and producer is needed to prevent liquid blocking inside the reservoir during the combustion process. This suggests that a well configuration that greatly decreases the distance between the injector and the producer would be advantageous in ISC based recovery methods and the well configuration used in SAGD comes to mind. Running SAGD in the initial periods creates a vapor-filled depleted zone in the reservoir which is hot enough to start combustion on air injection.
To investigate the possibility of this idea, a hybrid experiment was conducted at a representative reservoir pressure. During the experiment, SAGD was operated in the model for a period and then combustion was started by switching from steam injection to air injection. A well arrangement was considered to help process operation, oil ignition, and combustion front formation. Residual oil and water saturations in the model were analyzed. Also, core samples were extracted from the model to evaluate asphaltenes and coke formation. It was concluded that it is possible to recover almost 70% of the original oil in place with a special kind of well arrangement.
Defining Horizontal Well Objectives in Tight and Unconventional Gas Reservoirs
Authors: Britt L. K. , Jones J. R. , Miller W. K. 
Published: February 2011

Abstract:
Horizontal wells have become the "industry standard" for unconventional and tight formation gas reservoirs. Because these reservoirs have poorer quality pay it takes a well planned completion and fracture stimulation(s) to make an economic well. Even in sweet spots in unconventional and tight gas reservoirs good completion and stimulation practices are required to achieve economic success. But what are the objectives of horizontal wells and how do we relate the completion and stimulation(s) to achieving these goals? How many completions/stimulations do we need for best well performance and/or economics? How do we maximize the value from horizontal wells? When should a horizontal well be drilled longitudinally or transverse? These are just a few questions to be addressed in this paper.
This paper focuses on some of the key elements of well completions and stimulation practices as they apply to horizontal wells. Economic optimization studies were conducted for tight gas reservoirs highlighting the importance of lateral length, number of fractures, inter-fracture distance, fracture halflength, and fracture conductivity. In addition to the tight gas completion and stimulation considerations, network complexity will also be considered. These results will be used to develop a horizontal well decision tree for evaluating the various drilling, completion, and stimulation issues encountered in horizontal wells in tight and unconventional gas reservoirs. Field examples will be used to highlight these strategies.
This work benefits the petroleum industry by:
Developing well performance and economic objectives for horizontal wells and highlighting the incremental benefits of various completion and stimulation strategies, Establishing well performance and economic based criteria for drilling longitudinal or transverse horizontal wells, Integrating the reservoir objectives and geomechanical limitations into a horizontal well completion and stimulation strategy, Developing a horizontal well completion and stimulation decision tree for pre-horizontal well planning purposes.
Front Self-Correction in the In-Situ Combustion
Authors: Oskouei S. J. , Moore R. G. , Maini B. , Mehta S. A. 
Published: February 2011

Abstract
Since it was discovered in the early 1900's, several improvements have been suggested for the in situ combustion technology. Top-down combustion displacement, is a process proposed for application with horizontal well technologies. In this configuration, air is injected near the middle of the reservoir, close to the overburden, through a horizontal well or a number of vertical wells. Fluids are produced from the reservoir through another horizontal well placed near the bottom of the reservoir. In this configuration, the combustion front moves downward in the gravity direction and displaces fluids to the production well.
Combustion front formation and its stability are major concerns in this arrangement. While the short distance between injector and producer addresses the cold oil blocking problem in the reservoir, it has the potential to create air fingers which could prevent stable advance of the combustion zone in a horizontal plane. Front self-correction must occur to prevent oxygen from fingering to the production wells.
To prove this idea, experiments at reservoir pressure were carried in a two-dimensional SAGD model with Athabasca bitumen. Air was injected into the SAGD steam chamber, from the middle, and fluids were produced from the bottom. Front advancing directions were monitored by a series of thermocouples located inside the model. It was found that combustion zone starts spreading horizontally in the model until it reaches a limiting point then it starts moving downward as a horizontal front. Despite heterogeneity of the oil saturation and relative permeability in the steam chamber and un-swept zones, the combustion front moved almost as a horizontal plane and no sharp fingers were recorded in the experiments. These experiments show that stable middle-down combustion is feasible.
Plunger Lift Optimization in Horizontal Gas Wells: Case Studies and Challenges
Authors: Sask D. , Kola D. , Tuftin T. 
Published: February 2011

Abstract
Plunger lift is a proven technique for lifting liquids from vertical gas wells flowing below critical velocity. The use of plunger lift in horizontal gas wells was not initially expected to provide any difficulties or challenges. While it has been relatively easy to make plunger lift function in horizontal wells, truly optimizing production has proven to be much more challenging.
One of the challenges of horizontal wells is moving liquids from the horizontal well bore to the tubing above the bumper spring assembly. To facilitate this bumper springs are landed as deep as possible, which creates operating challenges for both bumper springs and plungers. Bumper spring check valve limitations were identified at high deviation angles and re-designed bumper springs have been deployed to address this. Recent testing has shown that the efficiency of some plunger types can be significantly reduced when used in horizontal wells and the explanation for this decrease as well as the test results are provided.
Plunger control software development for the Sierra field's horizontal well application has led to increased production times and volumes. It has resulted in additional operational benefits that reduce down time caused by cold weather and pipeline pigging operations. The software is embedded into the SCADA control system and can utilize well parameters monitored within SCADA to vary the plunger control parameters.
This paper presents case studies showing the impact of plunger control software for horizontal wells. Case studies detailing operational performance benefits and the performance of various types of plungers in high angle applications are also presented. Additional case studies show the impact on plunger performance of well bore trajectory and liquid hold up in the horizontal well bore. Continuous improvements to strategies and operations have been implemented to fully optimize horizontal gas wells.
Relationship Between the Hydraulic Fracture and Observed Microseismicity in the Bossier Sands, Texas
Authors: Guest A. , Settari A. 
Published: February 2011

Abstract
In the past years, an increased effort was directed to improving our understanding of hydrofracturing by microseismic monitoring and analysis. We are developing a numerical method that would predict microseismicity occurring during hydrofracturing and the influence of fracturing on the permeability of the reservoir. The core of our technique is a representative pre-fractured volume of the reservoir that deforms locally and allows for the coalescence of deformation as the stress reequilibrates. Such an approach allows not only for implementation of the geological and seismic information on the scale of the representative volume but also to follow the deformation at the scale of the complete hydrofracture. We apply this technique to the hydrofracturing of the Bossier sandstone. The main goal is to predict observed microseismicity and permeability changes of the reservoir based on the modeled strains. The results show that the distribution of microseismicity is dependent on the regional stress state and the heterogeneity of the stimulated domain. If the permeability is calculated from the strains developing in the reservoir during the treatment, permeability will increase mostly in the areas of active fracturing. The next step is to fully couple the poroelasticity and the geomechanical response and to fit the model to the engineering parameters during the treatment.
Evolving Recovery Technologies Directed Towards Commercial Development of the Grosmont Carbonate Reservoirs
Authors: Yuan J-Y. , Jiang Q. , Russel-Houston J. , Thornton B. , Putnam P. 
Published: February 2011

Abstract
Starting in the 1970s, Union Oil Company of Canada (Unocal), in partnership with Canadian Superior and the Alberta Government, conducted a series of exploratory field tests in the bitumen-saturated carbonate rocks of the Grosmont Formation. These tests applied thermal recovery technologies, including steam drive and cyclic steam stimulation (CSS), that were in their early stages of development. Significant amounts of production and observational data were obtained. Although some results were encouraging, activities in Grosmont were eventually stalled in the mid 1980s as economic attention was shifted to Cold Lake and Athabasca Cretaceous siliclastic reservoirs. Since then, in situ bitumen recovery, 3D seismic, horizontal well and surface processing technologies have matured significantly. In light of the enormous resources (406 billion barrels) hosted within the Grosmont Formation, it is pertinent to ask whether those new technologies are applicable for carbonate reservoir development.
To answer this question, we studied data from the Unocal pilots conducted in the Grosmont C and augmented it with recent laboratory tests on newly acquired Grosmont C cores. The previous pilot CSS results were encouraging, with the cycle steam-to oil ratio as low as 3.65 and a peak rate of 440 bbls/d from a single vertical well. With subsequent cycles the ratio of the produced fluid to the injected fluid increased, signifying the injected energy was retained and more effective in later cycles. The operation strategy of the Unocal pilots and its implementation were not optimal and we believe that this could be improved with modern techniques.
Based on our new understanding of the Grosmont Formation and specifically the Grosmont C, a numerical model was created and verified with production data. Model results indicate that the application of SAGD will be a commercially viable recovery process for Grosmont carbonate reservoirs and that low pressure injection (below 3500kPa) would be desirable. The laboratory tests not only support these conclusions but also suggest that performance of the applicable thermal processes can be enhanced with the addition of solvent. A SAGD/solvent pilot test is planned to start up in late 2010. This pilot will be critical to the development of exploitation strategies applicable to Grosmont carbonate bitumen resources.
Characterization of Production Commingled From Deep Basin Plays, Wild River Region of Western Alberta
Authors: Dixon R. K. , Flint D. W. 
Published: February 2011

Abstract
Previous study of unconventional tight gas plays in the Deep Basin area of the Western Canadian Sedimentary Basin identified a rapidly increasing volume of production and EUR developed in wells where production is commingled from multiple reservoirs in stacked plays. Historically, most Deep Basin wells were drilled for a primary target play – a single play strategy – and completed producing from a single play. However from 2007 to 2008, over 40% of the EUR connected in all Deep Basin plays was from multiplay producers. Extensive commingling to maximize the recovery per well and reductions in segregation and testing costs should improve well economics and increase total recovery. However, commingling multiple plays often obscures information important for resource characterization by play, such as: EUR per zone, individual zone productivity, producing success by play and well spacing by play.
Commingling is especially common in the Wild River region of the Deep Basin area, where up to eight potential plays may be stacked for completion. This paper will discuss the characteristics and distribution of commingled wells in the Wild River region. What is the impact of these multi-play wells in terms of activity, EUR connected and supply compared to single play wells? Where are the commingled play wells located? Which plays are targeted in terms of zones penetrated? Which plays are completed most frequently in these commingled wells? Is recovery per well improving with experience? Does recovery improve as more plays are completed? What is the overall success rate in this area? What is the density per section of Deep Basin producing wells? How do strategies and results vary by operator?
Based on the results observed in the Wild River region, the implications for resource estimates and development in other areas of the Deep Basin will be discussed.
The Tradeoff Between Surfactant Costs and Water Heating to Enhance Friction Reducer Performance
Authors: DeMong K. , Sherman D. , Affleck B. 
Published: February 2011

Abstract
In slick water fracture stimulations the standard treatment utilizes water with very few chemicals. In the Horn River Basin during the winter months the water from surface sources can be very cold. Besides the obvious problem of freezing, the low temperature of the frac source water causes serious problems with the effectiveness of friction reducers by increasing the inversion time (the time to maximum friction reduction). In low temperature, high rate conditions the maximum friction reduction may not be reached as the fluid may have travelled a considerable distance through surface equipment, and even down the casing, without the friction reducer being fully effective. This condition can increase pumping pressure, horsepower charges and surface equipment failures. It can also affect the ability to get to design rates for the frac resulting in undesirable conditions such as extending the time to get to rate, being unable to start sand scours or pressuring out early on in the frac treatment.
To solve the problem there have been two key solutions employed: either the water can be heated to a temperature where friction reducer inversion time is reduced and therefore is more effective, or more friction reducer is added to the cold frac source water until the friction pressure is manageable. On a multiple frac campaign in the Horn River these two methods were tested against a novel chemical that increased the effectiveness of the friction reducer in cold water. The presentation will include the field test data and a cost analysis of implementing this on a job by job basis. In addition, the foaming and flow back characteristics of this chemical were tested at near in situ conditions to determine the potential for unplanned consequences.
In addition, the technique is being considered for use in a system where the primary fluid is warm (~ 25°C) brackish produced water but the auxiliary fluid supply may be fresh cold water. The objective is to show the cost and benefit of the chemical solution compared to heating or increasing friction reducer loading. Field testing was required to determine if the chemical solution could be applied more cost-effectively then inline heating of the cold frac water supply at full frac rate. Field testing was also conducted to determine if cold frac source water could be efficiently friction reduced with no external heating using only friction reducer, or a combination of a friction reducer and a novel chemical to reduce inversion time.
Prospects of Use of the Ecological Equipment for Clearing of Water Objects of Oil
Authors: Vorobiev D. S. 
Published: February 2011

The theme of protection of water objects always was and will be вы со ко пр ио ри те тн ой. At federal level it is expressed in one of last documents - Water strategy of the Russian Federation to 2020 [1]. With a view of water improvement of quality in water objects, restoration of water ecosystems and recreational potential of water objects the decision of the basic “problem” problems is required: –Reduction of anthropogenous influence on water objects and their water modular territories;–Prevention of degradation of the small rivers;–Protection and prevention of pollution of underground water objects.
For restoration and protection, and also as prime actions anthropogenous influence dispersed (ди фф уз но го) a drain is necessary to reduce arrangements of the small rivers, to restore self-clearing ability of the rivers, to realize a complex of actions for ecological rehabilitation of the small rivers in cities and rural settlements. One of strategic targets is allocated: «protection and restoration of water objects to a condition providing ecologically favorable living conditions of the population, assume the decision of some problems on decrease in anthropogenous loading on water objects, protection of underground waters from pollution, rehabilitation of water objects and liquidation of the saved up ecological harm [1].
Strategy provides realization of the actions directed on restoration of water objects and liquidation of the saved up ecological damage.
The Integrated Approach to the Prediction of Water Shut-Off Jobs Effectiveness
Authors: Strizhnev .  A. , Ilyasov .  M. , Lomakina .  Y. , Kornilov .  V. 
Published: February 2011

Summary
This paper presents an integrated approach to the optimization of properties and volumes of chemicals by the example of water shut-off work-overs in vertical and deviated producing wells completed in sandstone reservoirs. It includes laboratory testing of water shut-off chemicals and mathematical modeling of its injection into the layered reservoirs. Testing the chemicals is necessary to optimize the selection of materials that suit best to the current reservoir conditions, numerical experiments on the presented model allows evaluating the technological and economical effect from the treatment.
Mathematic Models for Interpretation of Temperature Changes in ESP Wells
Authors: Valiullin . A. , Ramazanov . Sh. , Fedotov . Ya. 
Published: February 2011

Abstract
Temperature transient analysis of oil and gas fields in Russia has long history. The paper is dedicated to application of temperature transient analysis for monitoring ESP wells. Currently several technologies of monitoring ESP wells are used on practice: ✓analysis of residual temperature distributions in wellbore after pumping equipment is pulled-out✓measurement along the wellbore in the formation intervals during moving of cable equipment, lowered by pump✓logging through tubing above the pump✓measurements with permanently installed sensors below ESP.
The analytical and numerical models of temperature transient analysis in the wellbore taking into account convective heat transfer, heat generation in the pump and electric motor, counter flow in annular space and thermo-hydrodynamic effects in reservoir are described. In particular the possibility of gas-liquid contact and oil-water contact determination in annular space based on temperature logging through tubing is shown. Obtained results are of the interest as for production monitoring as well as for the control and management of pump-lifting equipment operations.
This paper presents the case studies of temperature logging conducted in ESP wells of oilfields of Russia.
Sidetrack and Well Deepening Operations in the Jurassic Formation of Vyngapur Oil Field
Authors: Pavel Kolba , Mikhail Klimov 
Published: February 2011

Abstract
One of the methods of extraction of remaining reserves used in JSC “Gazpromneft-Noyabrskneftegaz” is sidetrack operations which also enable to involve fishing well stock of oil fields. Efficiency of these arrangements depends mainly on cooperation of specialists in geology, field development and drilling. At present, interaction pattern between subdivisions of the Company and contractor drilling organizations is developed which allows to perform full cycle of implementation of sidetracks starting with selection of wells and finishing geological support of drilling operations. Permanent field development monitoring of perspective oil deposits, application of the developed well selection technique and analysis of geological features using state- of-the-art program packages of seismic interpretation, geological and simulation modeling packages encouraged successful drilling jobs in the selected wells, getting agreement of actual flow rates and forecast and, as a result, increase of incremental oil production of the Company.
A New Approach in Modeling Hydraulic Fractures and Auto Fractures at Injectors in Full-field Models
Authors: Bogachev K. Yu. , Shelkov V. G. 
Published: February 2011

Abstract
Realistic simulations of full-field models including hydraulic fractures made at producing and injecting wells, and fractures created automatically, when the bottom hole pressure at injectors exceeds the overburden pressure remains problematic in the most commercial hydrodynamic simulators. The existing software can either provide a very detailed fracture dynamics description for one or few wells with high grid resolution and precise fracture geometries, or provide full-field modeling with many wells and skin-factors used to account for hydraulic fractures. With model grids getting finer resolution it becomes more common to have the fractures half length to exceed the grid block sizes.
In the existing hydrodynamic simulators it is the realistic description of large fractures that remains the most problematic issue. In the absence of adequate modeling solutions the reservoir engineers are forced to come up with a set of unphysical approximations causing significant distortions of model properties and deterioration of its forecasting power. The new technology proposed in this paper is based on building networks of new (“virtual”) well perforations in the model grid blocks intersected by the fracture. With the help of this new approach, reservoir engineers can realistically model fracture dynamics in full-field models with hundreds and even thousands of fractured wells.