bluuebunny/crossref_metadata_2025 huggingface dataset:
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

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

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

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

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

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

It 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

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

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

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

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.
Tight Oil Production Analysis: Adaptation of Existing Rate-Transient Analysis Techniques
Authors: Clarkson C. R. , Pedersen P. K.
Published: February 2011

Low-permeability (tight) oil reservoirs have emerged as a significant source of oil supply in North America. Hydraulic fracturing techniques combined with horizontal well technology have enabled commercial production from oil and gas reservoirs with absolute permeability < 0.1 md, and recently in gas reservoirs with permeability in the nanodarcy range. Techniques for quantitative analysis of ultra-low permeability reservoirs completed with hydraulically-fractured horizontal wells are in their infancy; complications that have slowed development of these techniques include complex reservoir behavior, such as dual porosity effects, multi-layer behavior, multi-phase flow and non-static absolute permeability, and complex flow behavior associated simultaneous flow of multiple hydraulic fractures into horizontal wells. Although analytical models have been and currently are being developed to simulate well performance associated with these complexities, systematic methods for analyzing production for the purpose of quantifying reservoir and hydraulic fracture properties have not been discussed in detail in the literature for tight oil reservoirs.

This paper examines the use of classic rate-transient techniques (flow-regime analysis, type-curve methods and simulation) for analysis of tight oil reservoirs. Single-phase (oil) flow associated with undersaturated black oil reservoirs (above bubble point) is the focus of this work. Simulated cases of multi-fractured horizontal wells completed in single porosity reservoirs, as well as naturally-completed horizontal wells in transient dual porosity reservoirs are analyzed. In all cases, the proposed integrated rate-transient analysis approach provided reasonable estimates of (simulator input) hydraulic fracture and reservoir properties. A field case of a multi-fractured horizontal well completed in a low-permeability area of the Pembina Cardium Field, Western Canada, is also given. Finally, a simplified method for forecasting horizontal wells completed in single and dual porosity media, using inputs derived from flow-regime analysis, is introduced.
Multioriented Fracturing in Unconventional Reservoirs Offers Improved Production by Better Connectivity
Authors: Surjaatmadja J. B.
Published: February 2011

In the oilfield, the term "unconventional" almost always means difficult to get, for one or another reason. One reason addressed in this paper relates to formations characterized by the lack of permeable features that connect or can be easily connected to the wellbore using conventional stimulation techniques. The common logic of placing larger and larger fractures does work but, when using this approach, the cost-over-reward ratio can be far from desirable.

It is well-known that placing a second fracture sometime later in the life of a well will result in a fracture that extends in a slightly different direction, mostly caused by the drainage of the fluid near the fracture face. In this situation, fracture redirection is probably caused by the pore-pressure decline near the producing fracture face. In some instances, the new fracture produces almost as if it has reached a new formation.

This paper discusses placement of such "second" (or third) hydraulic fractures within the same time domain from the same wellbore section. It is believed that the first fracture will modify the stress field to a perpendicular direction. Combined with the hypothesis of the hard-to-accept concept that fractures often shy away from the most productive areas, this approach will cause the second fracture to extend directly into the more productive areas, thus providing a substantial production boost.
Methods and Tools for the Development of Consistent Reservoir Rock Type Based Relative Permeability and Capillary Pressure Models for Reservoir Simulation
Authors: Kralik J. G. , Guice K. , Meissner J. P.
Published: February 2011

A workflow for generating internally consistent sets of saturation functions from capillary pressure and relative permeability data for use in numeric reservoir simulation is described. This workflow was implemented in software that was developed to facilitate the filtering and grouping of these data using a variety of screening criteria. Such implementation ensures the application of consistent practices, based on the physics of multiphase displacement in porous media, when developing relative permeability and capillary pressure models. The data are reviewed to confirm that they are of acceptable quality prior to use in saturation function development. The workflow described here conforms to the displacement categories defined in the simulation model, e.g. families of reservoir facies. In addition to grouping and analyzing SCAL data (capillary pressure, relative permeability, wettability) for a specific reservoir, the software can access a larger database that contains all available SCAL data. The database also provides convenient access to analog data for reservoirs in which sufficient SCAL data have not been generated. To our knowledge, such a systematic method for the development of consistent capillary pressure and relative permeability saturation functions based on families of reservoir facies for simulation has not been presented in the literature.

Saturation endpoints are first established by analyzing the appropriate capillary pressure data (e.g., primary drainage Pc for Swir, primary imbibition water-oil Pc for Sorw, primary drainage gas-oil Pc for Sorg, etc.). This analysis involves fitting the data to a consistent constitutive equation that contains the saturation endpoint as a regression parameter. The resulting models should be compared to any available field data to ensure consistency (e.g., primary drainage Pc vs. calibrated log Sw(z)). Once the saturation endpoints have been established, the grouped relative permeability data are analyzed, starting with the bounding water-oil primary drainage data. After defining the bounding primary drainage curves, the primary imbibition krow-krw curves can be developed. Individual imbibition krow-krw tests generally correspond to unique imbibition scanning curves rather than the bounding primary imbibition curve, suggesting the measured imbibition curves be scaled to the bounding primary drainage kro curve to ensure consistency. Secondary drainage kro-krwo data, if available, are similarly scaled. Three-phase gas-oil primary drainage krog-krg and primary imbibition kro-krgo data are treated in an analogous manner. This process is applied to each group of capillary pressure and relative permeability data. Experience has shown that this approach properly represents the displacement physics, facilitating accurate reservoir performance predicitions and history matches.
Flaws in Fracture Designs: A Continuing Problem
Authors: Marongiu-Porcu M. , Liu W. , Economides M. J.
Published: February 2011

Although hydraulic fracturing has become the second largest outlay of petroleum companies after drilling, design and execution issues are still heavily contaminated by lingering misconceptions and inadequate empirical "rules-of-thumb". Some of the most common problems include issues such as "maximizing" fracture conductivity or fracture length (sometime referred to as "effective" or "apparent"), or even more inadequate goals during execution such as cutting costs by shortening the injection time and using the cheapest possible proppants.

Since the introduction of the Unified Fracture Design (UFD) approach, practitioners have a coherent method to design fracturing treatments aiming to maximize the post-treatment productivity index. The central idea of the UFD technique is to select an optimum compromise between propped fracture length and width, for a given proppant volume and depending on the properties of the reservoir and the selected proppant.

We present in this paper a wide range of parametric studies for oil and gas reservoirs with permeability ranging from 0.01 md to 500 md, and we assess the impact of treatment size (mass of proppant injected) and proppant pack permeability, starting from the UFD-determined optimum designs and then departing towards suboptimal conditions. These include fracture length, the fracture conductivity and fracture height (by using the concept of fracture aspect ratio). We also apply the same approach to study gas wells, in which turbulence effects in moderate to high permeability reservoirs require the adjustment of optimum design geometry. Finally, we show how a proper candidate selection among a given portfolio for hydraulic fracturing treatments can easily provide a much higher incremental production from a much smaller number of treatments. We use both vertical and horizontal well fracturing.

Our results show clearly that there is a lot of room for improvement in fracture designs for production enhancement, particularly dealing with larger treatments and the selection of better quality proppants (higher pack permeability), especially for gas wells. This leads to a systematic approach for design and a studious departure from optimum design conditions, when necessary, based on field constraints and reservoir and fluid characteristics.
Relative Permeability of CBM Reservoirs: Controls on Curve Shape
Authors: Clarkson C. R. , Rahmanian M. R. , Kantzas A. , Morad K.
Published: February 2011

Relative permeability to gas and water for 2-phase flow coalbed methane (CBM) reservoirs has long been known to exhibit a strong control on (gas and water) production profile characteristics. Despite its important control on both primary and enhanced recovery of CBM for coal seams that have not been fully dewatered, relative permeability in coal has received little attention in the literature in the past decade. There are few published laboratory-derived curves; these studies and their resulting data represent a small subset of the commercial CBM reservoirs and do not allow for a systematic investigation of the physical controls on relative permeability curve shape. Other methods for estimation of relative permeability curves include derivation from simulation history-matching, and production data analysis. Both of these methods will yield pseudo relative permeability curves whose shapes could be affected by several dynamic CBM reservoir and operating characteristics.

The purpose of the current work is to perform a systematic investigation of the controls on CBM relative permeability curve shape, including non-static fracture permeability and porosity, multi-layer effects and transient flow. To derive the relative permeability curves, effective permeability to gas and water are obtained from flow equations using a modified version of the approach described by Clarkson et al. (2007). Simulated cases are analyzed so that derived and input curves may be compared allowing for investigation of CBM reservoir properties on curve-shape. One set of relative permeability curves that were input into the simulator were derived from pore-scale modeling. Field cases from two basins are also examined and controls on derived relative permeability curve shape inferred. The results of this work should be useful for future CBM development and greenhouse gas sequestration studies, and it is hoped that it will spark additional research of this critical CBM flow property.
Evaluating Unconventional Reservoirs: The Questions We Need to Answer
Authors: Russum D. A.
Published: February 2011

North America has embraced unconventional gas reservoirs as the solution to declining conventional production, and today virtually every E&P company has some unconventional gas reserves or resources in their portfolio. As North America demonstrates success in our unconventional reservoirs, interest in unconventional opportunities is spreading to basins throughout the world.

However, as unconventional opportunities grow and develop, the consistent evaluation of unconventional resources and reserves is becoming a major issue for our industry. The newness of many unconventional plays means historical trends are limited. In addition, no two unconventional plays are the same and variations within a play can yield substantially different results.

Evaluators and their clients need to consider many issues in order to determine the real value of an unconventional opportunity. Early and regular discussion between clients and their independent evaluators ensures that the right questions are being asked and those questions are answered as efficiently as possible. While it is important that evaluators provide an independent opinion of resources and reserves, this opinion is weaker when it fails to take into account all the relevant information possessed by the client.
Mapping Key Reservoir Properties Along Horizontal Shale Gas Wells
Authors: Khalid S. , Faurschou K. , Gorchynski T. , Zhao X. , Marechal F. C.
Published: February 2011

Heterogeneity of properties along horizontal shale gas wells has a significant impact on the quality of completion as well as on production from each stage. This heterogeneity can exist in the quality of the reservoir, such as changes in kerogen content and maturity, free porosity, and water saturation, and it can also be seen in factors which directly affect the course of induced fracturing in the well. These factors can be faults, natural fractures, stress regime changes, etc.

Historically, it has been difficult to map these properties because some of the measurements required logging in openhole environments using wireline tools. Recently, logging-while-drilling and through-casing-logging measurement techniques have been developed to achieve similar results in a safer, more controlled environment.

A large number of horizontal wells have been drilled in gas shales in the USA and Canada. Some of these wells have been logged in an attempt to understand variability. The authors have studied these data sets in detail, and the concepts presented here are based on observations from these data sets. We use a data set acquired in a Canadian shale as an example to illustrate the concepts of property heterogeneity along the laterals. This well is a 1,000-m long lateral which was supposedly drilled in the same, homogeneous rock, yet it shows substantial property differences along its length, suggesting the importance of evaluating horizontal wells.

Once these properties have been mapped, many questions can be raised. Can we increase production from the same horizontal well, which has already been drilled (Potapenki et al SPE 119636; Ketter et al SPE 103232) ? Can we do something better in planning the completion to get more gas out of it? Would it be possible to save a well from geohazards if we knew how we might connect to them? Can we select the optimum perforation interval when we know the quality of cement behind pipe? The answer to each of these questions can result in substantial gains in efficiency and reduction in risk, while providing major production boosts. To determine definitive answers to these questions, production data over time would need to be analyzed. These data were not available at the time of writing this paper; hence, a detailed discussion on the specifics of the correlations between properties and production is left for another paper.
Analyzing Production Data From Tight-Oil Wells
Authors: Kabir C. S. , Rasdi F. , Igboalisi B.
Published: February 2011

Performance prediction of wells producing from tight microdarcy formations is a daunting task. Complexities of geology (the presence/absence of naturally occurring fractures and contribution from different lithological layers), completion and fracture geometry complexities (multiple transverse and/or longitudinal fractures in long horizontal boreholes), and two-phase flow are impediments to simple performance forecasting.

We demonstrate the use of various analytical and numerical tools to learn about both short- and long-term reservoir behaviors. These tools include (a) traditional decline-curve analysis (Arps formulation), (b) Valko's stretched-exponential method, (c) Ilk et al's power-law exponential method, (d) rate-transient and transient-PI analyses to ascertain the stimulated- reservoir volume, and (e) numerical simulation studies to gain insights into observed flow regimes.

The benefits of collective use of analytical modeling tools in history-matching and forecasting both short- and long-term production performance of tight-oil reservoirs are demonstrated with the use of real and simulated data. Diagnosing natural fractures, quantifying stimulated-reservoir volume, and assessing reliability of future performance predictions, all became feasible by using an ensemble of analytical tools.
Fully-Coupled Wellbore Design and Optimization for Thermal Operations
Authors: Kumar A. , Oballa V. , Card C. C.
Published: February 2011

Steam Assisted Gravity Drainage (SAGD) is a widely used enhanced oil recovery process applied in Canadian oil sands projects. Operators of SAGD projects have long been aware that many factors such as near wellbore geology, tubular sizes, lengths, and the allocation of fluid rates between tubulars in multi-string completions, can significantly impact the effectiveness of well and well- pair operations. The interaction of well components within these complex wells and the reservoir can impact the economic and technical success of the entire project either positively or negatively, suggesting that a means of optimizing this interaction that couples wellbore effects with the reservoir is required. Simulation studies were carried out to investigate the impact of wellbore design optimization on the well's performance. Reservoir simulation was used as a tool to evaluate the advantages derived from the optimization of wellbore and tubular design for thermal projects using a new fully coupled reservoir-wellbore modeling approach linked to an optimization algorithm.

This paper presents results that cover important aspects such as the impact of geological heterogeneity on wellbore design; the optimization of length and positioning of multiple tubular strings within a liner for both injection and production wells; and the optimization of the allocation of injected steam between multiple tubing strings. The results indicate positioning of tubulars in a multiple tubing completion SAGD well pair have a significant impact on the steam chamber growth, productivity, SOR and ultimately on NPV. This paper presents results of two optimization cases. The base case wellbore completion had two tubing strings, the short tubing string was landed at the heel while the long tubing string was landed at the toe of the horizontal SAGD well pair. First optimization was performed by changing the length/placement of tubing strings in the injector and the producer. Optimization of tubing placement increased the NPV of the well pair from 16.3 M$ to 20.7 M$ over 8 years. The Second optimization study was performed including the tubing placement similar to the previous case along with the SAGD operating strategy in terms of steam injection rate that was allowed to change every two years. In this case the NPV was optimized from 16.3 M$ to 25.79 M$ over 8 yrs.
Reducing Exploration and Appraisal Risk in Low-Permeability Reservoirs Using Microseismic Fracture Mapping
Authors: Cipolla C. , Mack M.
Published: February 2011

Low-permeability reservoirs have been actively developed and considered economically viable for more than 30 years in North America, but their development has been limited elsewhere. In North America, significant infrastructure is already in place and drilling and completion costs are relatively low. The typical exploration and appraisal approach is to drill a relatively large number of low cost wells to assess economic viability. Outside North America, however, infrastructure is less developed, and costs are often higher. To achieve economical development in these areas, operators must assess resource viability by drilling as few wells as possible. The many-wells model has made international operators reluctant to explore low-permeability reservoirs in some areas. However, there is increasing interest in developing the vast resources held in tight gas, coalbed methane, and gas shale plays outside North America.

The exploration and appraisal of low-permeability reservoirs or unconventional plays is significantly different than conventional reservoirs; exploration is more like appraisal, requiring pilot programs to test commerciality of these resource plays prior to embarking upon large-scale development (Hall 2007; Stabell 2007), including the effect of completion and stimulation optimization (Haskett and Brown 2005). One essential component of low-permeability reservoir development is hydraulic fracturing, which virtually all of these wells require. With the introduction of hydraulic fracture monitoring (HFM), we are now able to measure fracture geometry and complexity, which has led to major improvements in treatment designs, well completions, and field development strategies in North America. HFM applications were once focused on development and infill drilling, but they have recently shown significant value for exploration plays (primarily in gas shale). HFM measurements now allow operators to more efficiently evaluate the effectiveness of stimulation treatments and completion approaches in exploration and appraisal wells, reducing the number of wells required to assess the economic viability of low-permeability reservoirs.

The application of HFM to exploration and appraisal programs outside North America could significantly accelerate the evaluation of low-permeability reservoirs, where selecting the appropriate hydraulic fracturing design and well completion strategy will be key to success. It could also accelerate the learning curve, which is essential to quickly reducing costs.
Numerical Study of Gas Evolution and Transport Behaviors in Natural Gas Hydrate Reservoirs
Authors: Uddin M. , Wright F. , Coombe D.
Published: February 2011

Gas hydrates are a potentially vast untapped source of natural gas. Recent numerical and field studies suggest the Mallik gas hydrate field in Canada's Mackenzie Delta may represent a technically producible and potentially economically viable reservoir of natural gas. Our initial reservoir simulations using a kinetic reaction approach indicate that gas evolution and transport within porous geologic reservoirs have a significant effect on fluid production characteristics, while field and laboratory data suggest that significant amounts of evolved gas can be trapped for some time within the reservoir, depending on the field operation.

In this work, we invoke modeling concepts extensively employed in quantifying gas ex-solution from very viscous oils to further assess the kinetic behaviour of gas hydrate ex-solution via depressurization. Here the gas bubbles can be categorized into three groups with explicit transport behaviour: small bubbles (water phase), large bubbles (immobile) and connected bubbles (or free gas). These concepts allow the development of a new set of kinetic reactions for hydrate dissociation: one representing the (possibly delayed) conversion of hydrate into water and dispersed gas bubble phases, and one representing the evolution from dispersed bubbles to connected bubbles. These reactions can effectively capture the non-equilibrium fluid flow behaviour observed in field production tests.

For modeling of the transport phenomenon, we assumed two explicit mobility formulations, 1) trapped bubbles (no mobility) and a flowing water phase, and 2) large connected gas bubbles and flowing water (with relative mobility). Relative mobility can be estimated by using traditional grid block relative permeability curves. We then develop a simple mechanistic gas bubbles trapping tool as a function of Capillary Number, which can easily be incorporated into our numerical simulator. This entrapment of the non-wetting gas phase results in higher values of critical gas saturation.

Two case studies based on alternative representations of a Mallik-like gas hydrate reservoir demonstrate that significant errors can result in reservoir modeling if these fluid transport phenomena are not adequately represented in numerical simulations. Aspects of the model developed here have been applied to history matching and prediction of natural gas recovery from clastic, sand-dominated reservoir at the Mallik Site.
Multi-Interval, Horizontal-Completion Strategies Minimize Water Usage and Deliver Increased Production
Authors: Palidwar T. , Nikiforuk G. , Noble V.
Published: February 2011

In recent years, the industry has shifted its focus toward developing unconventional and conventional tight-oil plays, which has led to a steep learning curve in the development and application of new technologies. This paper discusses the progression and findings of operators in a Canadian unconventional oil play, and how current techniques are providing operators with reduced stimulation costs and improved fracture placement, leading to higher initial production rates and cumulative production.

With the advancement of horizontal drilling and completion techniques, operators are revisiting oil plays that had previously been developed with vertical wells or unstimulated, horizontal wells. In many cases, these plays were uneconomic to pursue, except during periods of higher oil prices. With recent improvements in horizontal-stimulation techniques, operators are now finding that cost-effective stimulation methods can be applied that improve the economics of both conventional and unconventional plays.

In one Canadian light-oil play, coiled-tubing (CT) conveyed, openhole fracturing was used initially as a stimulation technique. Production gains were noted, but the water from an adjacent zone limited the effectiveness of this technique. Operators then proceeded to use openhole packer completions as a means of controlling the fractures. This method provided positive isolation between openhole compartments but limited the number of zones that could be completed as well as the options available for workovers following the fracture treatments. More recently, operators have successfully used monobore drilling and completion techniques with a CT-deployed straddle frac stimulation method, providing both economic and low-operational-risk wells at lower drilling and completing costs.

The benefits of the monobore drilling and completion systems are:

Reduced drilling time over other methods Single-stage cementing options Single-trip perforating Full-diameter wellbore simplifies completions. Flexibility in number of intervals and spacing Fracture treatments designed are to maximize zonal coverage Ability to control fracture placement to avoid nearby water zones Flexibility to alter job design during treatment Ability to return to the well following the initial treatment for future treatments Lower water requirements for stimulation Reduced costs lessen environmental impact with reduced water volume Reliable, proven, straightforward process

Compared to other methods, this monobore and CT-straddle frac system has provided a lower-risk, engineered approach for delivering higher initial rates and increased cumulative production throughout the life of the well. It has also lead to the development of tight-oil reserves located outside of the conventional production fairways.