bluuebunny/crossref_metadata_2025_split huggingface dataset:
Drilling a Better Pair: New Technologies in SAGD Directional Drilling
Authors: Zimmer C. , Person J. , Richter D. , Tilley J. , Bittar M. 
Published: February 2011

Abstract
The precise placement of well pairs is one of the most crucial factors in the successful execution of a steam assisted gravity drainage (SAGD) drilling program. A SAGD drilling program includes placing the producer well relative to the reservoir boundaries, as well as accurately twinning the producer with the injector well. Delivering on these high expectations in unconsolidated formations, such as the McMurray oil sands, requires a strong focus on technological innovation.
A common practice in drilling SAGD wells in northeast Alberta is to drill lateral SAGD pairs with conventional steerable mud motors and logging-while-drilling (LWD) resistivity measurements. Although this combination has delivered success, certain limitations exist in terms of wellbore quality and placement. At the Statoil Leismer Demonstration Project, several industry firsts were successfully implemented, including a combination of the newest and most cutting-edge directional, measurement, and LWD technology.
The keystone of these industry firsts was the application of a soft formation modified, point-the-bit rotary steerable system (RSS), used on 20 horizontal wells. Combined with an ultra deep azimuthal resistivity sensor, the RSS provided precise geosteering along the bottom bed boundary in the producer wells, resulting in improved reservoir capture and reservoir characterization. More on-bottom time enabled more efficient drilling and significantly reduced well costs. Smooth, almost effortless liner runs reflected the lack of tortuosity in the wellbore, made possible by the rotary bottom hole assembly (BHA). Improved directional control made uniform well separation possible between lateral pairs, thereby reducing the risk of hot spots and short-circuiting during SAGD operations. The use of an even-walled power section above the RSS increased the bit RPM for improved BHA responsiveness while minimizing casing and pipe wear. Overall, the results and lessons learned from the demonstration of these new techniques provide a clear indication of the progressive future of directional drilling in SAGD.
The Comparisons of Production Behavior of Gas Producing From Gas and Gas Hydrate Reservoirs
Authors: Bai Y. , Li Q. 
Published: February 2011

Abstract
A mathematical model is firstly developed to describe the hydrate dissociation, in which the effects of the flow of multiphase fluid, the kinetic process and endothermic process of hydrate dissociation, ice-water phase equilibrium, convection and conduction are considered. Based on the model, the comparisons of production behavior between gas and gas hydrate reservoirs are presented. Numerical results show that the gas rate of gas reservoir is higher than that of gas hydrate reservoir under the same condition. However, the period of stable production of gas reservoir is shorter than that of gas hydrate reservoir. The water rate of gas hydrate reservoir is higher than that of gas reservoir. Moreover, the moment that the water rate rises to the maximum value is later with the increase of reservoir initial pressure. Results also show that the difference of cumulative gas volume between gas and hydrate reservoirs decreases with the increase of the initial pressure of reservoir. When the initial pressure of reservoir reaches a certain value the cumulative gas volume of gas reservoir exceeds that of gas hydrate reservoir. The pressure depletion in gas reservoir is faster than that of gas hydrate reservoir due to the permeability reduction caused by the solid gas hydrate.
Investigation of Polymer-Enhanced Foam Flooding With Low Gas/Liquid Ratio for Improving Heavy Oil Recovery
Authors: Pei H. , Zhang G. , Ge J. , Wang J. , Ding B. , Liu X. 
Published: February 2011

Abstract
Severe viscous fingering during water flooding of heavy oil leaves a large amount of oil untouched in the reservoir. Improving sweep efficiency is vital for increasing heavy oil recovery. Previous researches have proved that foam flooding can increase the sweep efficiency and control gas mobility, and thus increase oil recovery. However, researches on foam flooding were always focusing on the effect of high gas/liquid ratio (The gas/liquid ratio is usually larger than 1:1). Little research was conducted on foam flooding with low gas/liquid ratio.
This paper presents the results of a laboratory study of polymer enhanced foam flooding with low gas/liquid ratio for heavy oil in Shengli oilfield. For polymer enhanced foam (PEF), the displacement medium is N2 mixed with surfactant as foaming agent and HPAM. The experimental investigation evaluated the performance of foaming agent and studied the use of polymer to enhance foam properties. Polymer enhanced foam flooding were performed in cores, sandpacks and 3D physical model to study the factors affecting displacement efficiency such as gas/liquid ratio, injection slug size, and the viscosity of crude oil. The results of sandpack flood tests showed that the tertiary oil recovery of polymer enhanced foam flooding with the gas/liquid ratio of 0.2:1 could reach 39% IOIP for heavy oil with the viscosity of 325mPa·s at 55, which was 11% higher than the alkali/surfactant/polymer flooding by injecting a 0.3 pore volume (PV) of the same chemical slug. However, the tertiary oil recovery decreased with the increasing viscosity of crude oil. The result obtained in 3D physical simulation indicated that polymer enhanced foam system had excellent profile modification effect to increase sweep area and thus increase oil recovery. The above results demonstrate that polymer enhanced foam flooding with low gas/liquid ratio is a promising economical method for improving heavy oil recovery after water flooding.
Intelligent Sensors for Evaluating Reservoir and Well Profiles in Horizontal Wells: Saudi Arabia Case Histories
Authors: Al-Buali Muhammad H. , Dashash Alaa A. , El Gammal Tarek , Arevalo Francisco , Torne Juan 
Published: February 2011

Abstract
Saudi Aramco drilling strategy has shifted from vertical to horizontal due to proven advantages in optimizing production and cost. Evaluation of horizontal wells presents new challenges for the industry, especially with increasing water production. Therefore, it is important to determine the flow profile, water entry points and productivity index for remedial action, such as water shut off or selective stimulation.
A new generation of production logging tools (PLTs) was introduced and utilized on some horizontal wet producers located in Saudi Arabia. The new PLT is comprised of arrays of spinners and sensors to log the entire cross section to describe precisely the horizontal flow regime. This PLT provides measurements of the downhole production and phases.
A comprehensive evaluation was conducted of this type of PLT using different acquisition methodology and deployment methods to understand the best logging procedure. Therefore, one set of the spinners and sensors was attempted into two wells while two sets were attempted in the other two wells. Also, the PLT was deployed using two methods, which are coiled tubing (CT) and wireline tractor. Consequently, a group of lessons learned was gained, and the best logging procedure was established. The operation and interpretation results indicated that the production profiles obtained using this intelligent tool are reliable and accurate.
This paper describes cases including planning, deployment, data acquisition, detailed analysis, results and lessons learned. A quality control of the data is also reviewed considering the importance of real time acquisition and validation of the information for future use in reservoir management or well intervention.
Case Study on Hayter Heavy Oil Pool Update, Alberta: Reducing Risk and Increasing Recoveries for Economic Heavy Oil Horizontal Well Placement
Authors: Mottahedeh R. R. 
Published: February 2011

Abstract
Systematic approach and detailed integrated geo-modelling work with reservoir engineering processes has yielded additional economic locations to an already mature development within a Section of land at 26-40-1W4 in the Alberta side and the border with Saskatchewan. The pool currently produces about 2700 BOPD of oil; it was near its economic life back in 2003.
Current well density is less than 4 acres, making it one of the most densely drilled Sections in Alberta. About 10 horizontal wells per year are drilled within the Heavy Oil pool in the last 8 years. The 12-16m sand is underlain by an active bottom water drive system. The 16 API oil pool recoveries have increased from about 17% to 25% so far.
The update will show how detailed understanding of oil in place, recovery mechanism and correct prediction of the conning through a geo-model as well as solutions to incorporate collision avoidance has resulted in near 100% success in the past 9 years.
Numerical Simulation of Heavy Oil (Bitumen) and Alkane Solvent Partitioning (HASP) Process
Authors: Mustafiz S. , Frauenfeld T. , Rajan R. V. 
Published: February 2011

Abstract
Phase partitioning experiments conducted at Alberta Research Council (ARC) have shown that Athabasca UTF bitumen and propane mixture partitions into a solvent-rich light oil phase and a heavy-ends-rich oil phase. The partitioning may have beneficial impact on the performance of a gravity based process such as VAPEX and other solvent based processes if the low-viscosity phases carries the bulk of the oil production, and the heavy phase left in the reservoir is mostly asphaltene and essentially immobile. It is considered essential to treat the bitumen as a multi-component fluid with asphaltene as one of the components in order to determine the fluid properties of the upgraded oil in the propane based recovery process. Bitumen was treated both as a single component and as a multi-component fluid in the numerical simulations of the propane based recovery process. Fluid properties such as gas-liquid K values for components representing the bitumen (saturates, aromatics, polars and asphaltenes), as determined through CMG-WinProp earlier, was used in the numerical simulations with CMG-STARS. The challenges involved in representing bitumen as a multi-component fluid in the simulation of the recovery process is discussed.
The Influence of Global Sea Level Changes on European Shale Distribution and Gas Exploration
Authors: Turner P. , Cornelius C. T. , Clarke H. 
Published: February 2011

Abstract
The unprecedented success of North American shale gas has lead to a proliferation of international shale gas exploration plays, particularly in Europe. Whilst differing basin geometries and structural geology provide significant local constraints on development strategies, global sea level changes provide a framework by which different stratigraphic intervals can be evaluated at a "continental" level. Using the Hallam Curve we have identified a number of global sea level maxima which correspond to significant periods of prospective gas shale deposition. These typically correspond to periods of relatively high sea level, frequently post-glacial, during which continental shelves were inundated and clastic sediment supply was limited because of the high base level. Under-filled marginal sedimentary basins appear particularly attractive exploration targets. Shales deposited under these conditions typically have geochemical and petrophysical characteristics comparable to North American shales which are currently in production.
Several orogenic events severely influence European shales in terms of organic maturity, hydrocarbon generation and fracture generation, key prospective horizons(in ascending stratigraphical sequence) include the Middle Cambrian Alum Shale, Lower Silurian (Llandovery), the Devonian (Fammenian/Frasnian), Lower Carboniferous (Serpukhovian), Lower Jurassic (Toarcian), the Upper Jurassic (Kimmeridge Clay) and the Tertiary Eocene and Oligocene shales common to central Europe.
This paper will outline the authors initial exploration strategy focusing on three main intervals: Lower Palaeozoic of Central Europe, the Namurian of NW England and the Jurassic Posidonia Formation of the Roer Valley Graben in Holland.
Reliability Improvement of Progressive Cavity Pump in A Deep Heavy Oil Reservoir
Authors: Wang Haiwen , Yang Daoyong 
Published: February 2011

AbstractIt is extremely difficult to produce heavy oil from a deep reservoir where oil produces together with sand in an unconsolidated formation. The traditional progressive cavity pump has found its limited reliability in such a deep reservoir due to a lower fluid level, which leads to a larger torque and heavier load as both the pump setting depth and forces imposed on the rod string are increased substantially. In this paper, a pragmatic efficient technique has been developed to improve reliability of the progressive cavity pump in a deep heavy oil reservoir where oil produces together with sand in an unconsolidated formation. More specifically, tapered thread has first been used to replace the conventional ones for strengthening the resistive torque of the entire string as the collar is identified as the weakest point from both field applications and force analysis. The rotary anchor equipped with scalable slips is then adopted to not only avoid the tubing bend generally resulting from the compressed setting anchor, but also be easily set at the bottomhole where sand is accumulated. In addition, a frequency converter is used to control the rotating speed, which allows the pump to be started and shut off smoothly. It has been found from over 200 wells that the newly developed technique can be used to greatly improve the reliability of the progressive cavity pump for increasing oil production from deep heavy oil reservoirs by significantly extending the life of the rod string.
CO2 Storage as Hydrate in Depleted Gas Reservoirs
Authors: Zatsepina O. Y. , Pooladi-Darvish M. 
Published: February 2011

Abstract
With the increasing concern about climate change, the public, industry, and government are showing increased interest towards reducing CO2 emissions. Geological storage of CO2 is perceived to be one of the most promising methods that could provide significant reduction in CO2 emissions over the short and medium term. However, one major concern regarding geological storage of CO2 is the possibility of leakage. Carbon dioxide under the pressure and temperature conditions encountered in most geological settings remains more buoyant than water. Processes that could lead to permanent trapping of CO2 include geochemical reactions with the formation of solid minerals. This trapping mechanism is attractive because it converts the CO2 into a solid compound. However, the time-scale of such reactions is perceived to be centuries to millennia. In contrast, the kinetics of CO2- hydrate formation — leading to trapping of CO2 in the solid form — is quite fast, providing the opportunity for long-term storage of CO2. In this paper, geological settings suitable for formation of CO2 hydrates are investigated. We study storage of CO2 in depleted gas pools of Northern Alberta.
Thermodynamic calculations suggest that CO2 hydrate is stable at temperatures that occur in a number of formations in Northern Alberta, in an area where significant CO2 emissions are associated with production of oil sands and bitumen. Simulation results presented in this paper suggest that, upon CO2 injection into such depleted gas reservoirs, pressure would initially rise until conditions are appropriate for hydrate formation, enabling storage of large volumes of CO2 in solid form. Numerical simulation results suggest that, because of tight packing of CO2 molecules in the solid (hydrate), the CO2 storage capacity of these pools is many times greater than their original gas-in-place. This provides a local option for storage of a portion of the CO2 emissions there.
In this paper, we study the storage capacity of such depleted gas pools, and examine the effect of various reservoir properties and operating conditions thereon. In particular, we study the effect of the in-situ gas in formation of mixed gas hydrate; the effect of rise in temperature as a result of the exothermic reaction of hydrate formation; the effect of initial reservoir pressure, temperature, and porosity; as well as conditions for avoiding the deleterious formation of hydrates around the wellbore.
Well Production Challenges and Solutions in a Mature, Very Low-Pressure Coalbed Methane Reservoir
Authors: Okotie V. U. , Moore R. L. 
Published: February 2011

Abstract
Coalbed methane (CBM) production in the San Juan Basin of northwestern New Mexico and southwestern Colorado has spanned over 30 years. Some parts of the field, such as the high-permeability Fairway, are now in a mature stage of reservoir pressure depletion. Optimization of well production operations in the Fairway presents many challenges because of its extremely low reservoir pressure (less than 100 psi in some areas), heavy coal fines production, difficult artificial lift challenges, increasing CO2%, and the presence of paraffin, inorganic scale and corrosion.
We use history matching by reservoir simulation to help diagnose the causes of well production inefficiencies and then plan how to mitigate them. Simulation of Fairway wells typically requires the use of an increasing reservoir permeability trend caused by coal matrix shrinkage with the desorption of methane and CO2. However, we have observed in some Fairway wells that below a reservoir pressure of around 300 psi, there is a flattening or even a decrease in the permeability trend. This shift in the permeability trend is likely caused by coal failure (i.e. a change in mechanical properties of coal) that is evidenced in the wells by an increased amount of coal fines production.
This paper is written in two parts. The first part presents the challenges we face in operating Fairway wells and the solutions we have developed to overcome them. Field observations and operating guidelines will be shared along with well intervention histories where we have seen success. The second part discusses our use of reservoir simulation to diagnose the causes of reduced well production efficiency.
Case Study: Drilling Horizontal Exploration Shale Gas Wells Efficiently by Collaboration of Subsurface and Drilling Teams Utilizing Geosciences Technology
Authors: Islam N. 
Published: February 2011

Abstract
Talisman Energy currently operates and pilots wells in frontier areas for shale gas development. Wellbore stability, and well control issues are the largest contributors to additional costs and non-productive time (NPT) while drilling exploratory, outpost, and wildcat wells. This is a hindrance to many logging and evaluating functions in pilot wells, which are critical to assessing future development decisions. Offset wells are relied upon to guide drilling decisions but in many exploration and frontier areas the nearest relevant offset well may be far away to even be geologically or structurally analogous. Tighter budgets, lower commodity costs, and commitment to lean culture mean that wells need to be drilled with as few surprises as possible by continuously executing the ‘no drilling surprises’ model adapted by other companies. This can be accomplished through continuous improvement cycles and collaborative approach between drilling and sub surface teams.
In Talisman's frontier areas, the only laterally extensive sub surface data available before a well is drilled is 2D seismic. Although sometimes overlooked, this can provide critical data about the structural features that might contribute to drilling NPT. An example could be subtle structures that might cause the well to deviate more than normal due bedding inclination or drastic changes in bed dips due to structure. Using a combination of seismic interpretation and geomechanical software, we have been able to accurately predict shear failure and pore pressure gradients along with geohazards that correlate to actual drilling events in pilot wells. This is done to predict a safe mud weight window, horizontal stress directions, and magnitudes for easier drilling operations. Usually, there is a critical disconnect from prognosis to execution. To avoid this problem, the same team that assists the asset in the wellbore stability modeling monitors the drill and makes recommendations to the drilling team as events occur. In shale gas operations, where pilot wells are critical to the assessment of long term development, accelerating the learning curve is essential. Through this collaborative approach between the asset, geomechanics, real time monitoring, and the drilling operations teams; we have been able to drastically reduce well time and costs.
Fracturing Horizontal Transverse, Horizontal Longitudinal and Vertical Wells: Criteria for Decision
Authors: Economides M. J. , Marongiu-Porcu M. , Yang M. , Martin A. N. 
Published: February 2011

Abstract
Fracturing has become ubiquitous in the petroleum industry to the point that, at least in North America, almost all natural gas and the vast majority of oil wells are fractured. In fact there are more fracturing treatments than there are wells because of multiple treatments in many wells. Because of recent activities in shale gas, hydraulic fracturing of horizontal wells has become increasingly popular. However, not all reservoirs lend themselves to the same fracture and well architecture.
Other than deviated wells which we do not recommend, to match proper well architecture (vertical versus horizontal) and number and size of treatments is a very important production engineering exercise. For gas wells one of the most important additional considerations is turbulence which happens in two places: the reservoir and then in the created fracture.
This paper will discuss production from vertical, horizontal transverse and horizontal longitudinal fractured wells. Calculations of the incremental performance of each configuration are done for both oil and gas wells, using rigorous models for fractured well performance.
There are physical and economic limits and criteria. For example, for gas wells in reservoirs above 0.5 md, there is an unacceptable reduction in the performance of each transverse fracture because of enhanced turbulence effects. In such case a vertical fractured well is preferable. There are also economic criteria for selecting which type of completion is the optimum choice. Very low permeability reservoirs while attractive in North America with its controlled costs, they may be very unattractive in other countries. We look at a range of reservoir and proppant pack permeabilities and discuss the optimization of fracture geometry. The paper not only delineates areas of indicated application of each well completion but it highlights the importance of considering the hydraulic fracturing process from the very start of wellbore planning. The processes involved in planning a wellbore for efficient decision making and maximum flexibility of choice are also described.