bluuebunny/crossref_metadata_2025 huggingface dataset:
Monitoring and Improving Water Injection Efficiency in a Structurally Complex Field
Authors: Rotondi M. , Binda A. , Draoui M. , Tsoumou A. , Tealdi L.
Published: October 2011

Understanding and capturing water influx behavior is crucial for correct reservoir management. Water injection efficiency is highly influenced by fault pattern, transmissibility and juxtapositions and petrophysical characteristics. Both structural and stratigraphic sequences could create permeability barriers, compartmentalization or thief zones that may lead to un-optimized injector placement and poor sweep efficiency. The field described in this paper is a pre-salt anticlinal structure filled with light oil. The formation is highly heterogeneous and characterized by complex syn-rift fault pattern that control the sedimentation and the basin topography. More than 30 different fluid contacts were observed. A lateral, weak and disconnected aquifer is present only in some peripheral of the field and the primary drive mechanism is mainly solution gas expansion. Dispersed water injection was seen as a solution to maintain reservoir pressure. Well production behaviour soon confirmed that the field is highly compartmentalised. Therefore an effort was made to capture this compartmentalisation by simultaneously integrating available static and dynamic data as seismic, wireline logs, PVT, MDT, well test and productions. Once every block was identified and injector wells drilled, basic material balance analysis was carried out to inject at voidage replacement. Tracer injection and salinity monitoring of produced water are used as useful indicators of water paths into the reservoir. On the other hand injectivity tests, fall offs and PLTs are performed to monitor injectors behaviour and identify possible thief zones. EOR techniques and new technologies as fresh water injection, polymer injection, etc. are already implemented or under evaluation to maximise water injection efficiency and field recovery factor.
Lattice Boltzmann Method for Simulation of Shale Gas Transport in Kerogen
Authors: Fathi Ebrahim , Akkutlu I. Yucel
Published: October 2011

Fluid mechanics of natural gas in organic-rich shale involves nano-scale phenomena which could lead to potential non-Darcian effects during gas production. In general, these are low-Reynolds number and non-continuum effects and, more importantly, pore-wall dominated multi-scale effects. In this study we introduce a new lattice Boltzmann method to investigate these effects numerically in simple pore geometries. The standard method has been developed in the 1980s to overcome the weaknesses of lattice gas cellular automata and has emerged recently as a powerful tool to solve fluid dynamics problems, in particular in the areas of micro-and nano-fluidics. The new approach takes into account molecular-level interactions using adsorptive/cohesive forces among the fluid particles and defining a Langmuir-slip boundary condition at the organic pore walls. The model allows us to partition mass transport by the walls into two components: slippage of free gas molecules and hopping (or surface transport) of the adsorbed gas molecules. Using the standard two-dimensional D2Q9 lattice, low-Reynolds number gas dynamics is simulated in a one-hundred nanometer model organic capillary and later in a bundle of smaller size organic nanotubes. The results point to the existence of a critical Knudsen number value for the onset of laminar gas flow under typical shale gas reservoir pressure and temperature conditions. Beyond this number the predicted velocity profile shows that the mechanisms of slippage and surface transport could lead to molecular streaming by the pore walls which enhances the gas transport in the organic nanopores. The work is important for development of new-generation shale gas reservoir flow simulators and it can be used in the laboratories for organic-rich shale characterization.
Lower Quality Natural Quartz Proppants Result in Significant Conductivity Loss and Reduction in Ultimate Recovery: A Case History
Authors: Syfan Frank E. , Anderson Robert W.
Published: October 2011

Progress in horizontal drilling and hydraulic fracturing techniques allow the oil and gas industry to get the most out of ultra tight, naturally fractured formations and unconventional reservoirs. The increasing price differential between crude oil and natural gas is resulting in unprecedented activity in the Bakken, Eagle Ford, Niobrara, and other oil rich shales. The industry is actively building drilling rigs and the fracturing companies are adding equipment and crews at an escalating rate to keep up with the market growth.

These events have placed demands on hydraulic fracturing consumables as never before. Proppant shortages are expected to worsen before additional capacity can begin to offer some relief. Consequently, more and more operating companies are pumping lower quality Natural Quartz Proppant (NQP) in deeper, hotter, and higher closure stress environments, some of which exceed conventional design limits. All this in an effort to maintain completion intervals which are comparable to the accelerated drilling programs.

Recent proppant testing indicates significant conductivity reductions over time as it relates to proppants with lower crush strengths when compared to the higher strength Northern Whites. These conductivity variations were identified using a Discrete Fracture Network (DFN) fracture simulation model which indicated substantial reductions in ultimate recovery and productivity over time. The conductivity and modeling results were compared to actual post-fracture analysis data in the Marcellus Shale. This comparison further substantiated the test results.

This paper challenges the industry concept that pumping lower quality crush resistant proppants in a shale reservoir will not result in productivity losses. The findings presented in this paper clearly show that creating and retaining fracture conductivity is a prerequisite to achieving high initial productivity, ultimate recovery, and maximizing project economics.
Environmentally Focused Crosslinked-Gel System Results in High Retained Proppant-Pack Conductivity
Authors: Holtsclaw Jeremy , Loveless David , Saini Rajesh , Fleming Jeff
Published: October 2011

This paper presents the retained conductivity results of a new environmentally focused fracturing fluid whose components are sourced from the food industry, as described in the US Code of Federal Regulations Title 21 (CFR 21) or the Generally Recognized as Safe (GRAS) affirmation process. The fluid is comprised of the following components: a low-residue polysaccharide gelling agent, a metal crosslinker, a surfactant, and a suite of breakers. The suite of breakers provides consistent fluid cleanup in retained conductivity testing in temperatures ranging from 120 to 200°F. Fracture conductivity testing was performed using a wet-gas cleanup protocol used in modeling hydraulically fractured wells.

Hydraulic fracturing and the environmental effects of the chemicals involved in the fracturing process have become the subjects of public discussion. This discussion has encouraged the petroleum industry to address public concern regarding the potential environmental impact of chemicals used in fracturing. Service companies have responded by improving their current chemical portfolio and developing new environmentally focused chemical technologies. This paper describes an environmentally focused metal-crosslinked polysaccharide fluid that not only is more environmentally acceptable under the criteria described in this work, but also has little or no proppant-pack conductivity impairment, as measured by fracture conductivity testing.

Wet-gas retained conductivity of 1-lbm/ft2 20/40-mesh Ottawa sand was performed with humidified nitrogen gas flow. Retained conductivity of 84 to 100% was obtained after wet-gas cleanup for temperatures ranging from 120 to 200°F under a 2,000-psi closure stress. All conductivity tests were performed between Ohio sandstone wafers with filter-cake buildup from dynamic fluid-loss testing. Wet-gas retained conductivity was verified by a third-party laboratory. These results indicate that a fracturing fluid can be designed using defined environmental criteria based on food grade materials to provide similar performance and excellent retained conductivity.
Permeability Estimation of Damaged Formations Near Wellbore
Authors: Shi Xiaoyan , Prodanovic Maša , Holder Jon , Gray K. E. , DiCarlo David
Published: October 2011

We propose a numerical model for permeability estimation in damaged formations (e.g. sediments invaded by fines or sand crushing remnants). Grains of two length scales are present, but only larger ones are load-bearing. Porous media were modeled in Itasca's PFC3D, ensuring mechanical stability and making the particle positions and arrangement available for pore throat network analysis. The standard network modeling approach for analysis of packing of nearly equal grains (Delaunay tessellation) cannot be used since grains of two different length scales create a high portion of distorted pores. The main novelty of this work is adapting the network flow model to work with two length scales, and we present both the network creation and flow model in the multi-scale case.

The effects of particle size and initial formation porosity on formation damage are studied in detail. Our study confirms that large particles tend to occupy the formation face, while small particles invade deep into the formation. Moreover, particles which are smaller than pore throats (entrances) impair permeability more than those larger than pore throats. Our study also indicates that a higher initial formation porosity leads to more particle invasion and permeability impairment. Thus in order to reduce formation damage, mud particle size distributions should be carefully selected according to given formation properties.

Despite some simplifications in our initial modeling, it may nevertheless serve as a tool to predict formation damage according to given parameters, and to understand the mechanism of formation damage from a microscopic point of view. Further, while our motivation is formation damage during drilling, the modeling presented is applicable to any situation where migration of finer particles impairs a granular or sandstone medium.
Sweep Efficiency of Heavy Oil Recovery by Chemical Methods
Authors: Kumar Rahul , Mohanty Kishore K.
Published: October 2011

The goal of the present work is to evaluate the recovery efficiency of a heavy oil by injection of brine followed an alkaline-surfactant (AS) formulation in a quarter 5-spot sand pack. Reservoir sand was packed in a 2D cell resembling a quarter 5 spot well pattern. Brine flood for 2.5 PV was followed by the alkali surfactant flood conducted at different salinities. The oil recovery, oil cut, emulsion type and pressure drop were monitored. The brine flood recovered around 33-35% of OOIP and additional 18-24% could be recovered by the alkaline-surfactant solution. At the high salinity, the incremental oil due to AS solution came out quick at a high oil cut. For low salinity, the incremental oil recovery was more gradual.
Pilot Testing Issues of Chemical EOR in Large Fractured Carbonate Reservoirs
Authors: Kiani Mojtaba , Kazemi Hossein , Ozkan Erdal , Wu Yu-Shu
Published: October 2011

Many world class large carbonate reservoirs leave behind at least half of the initial oil in place. Typically water injection is used to improve oil recovery while gas injection is used to maintain pressure or to promote oil gravity drainage. Immiscible gas injection, including injection of CO2, has been implemented on a large scale in only few fields for economic reasons. Furthermore, interest in using surfactants in large carbonate reservoirs has recently flourished. As a result, we began to investigate the viability of designing and conducting a manageable pilot test program in a large fractured carbonate reservoir using a single-well, dual-completion system to evaluate the efficacy of the surfactant oil mobilization and oil capture. However, pilot testing in large reservoirs is very expensive and requires a long time to complete. These issues are less problematic in pilot testing of small and thin reservoirs in onshore field.

In this paper we present the results of a conceptual model to simulate the performance of surfactant flooding in the above-mentioned pilot test configuration. Three different model formulations, having different approaches to gridding and grid-refinement, were used. These include the dual-porosity, dual-permeability, and conventional variable permeability-porosity formulations to simulate fracture-matrix interactions. Simulation of pilot tests using dual-porosity models shows that gravity is most effective during waterflood but not as effective during the surfactant injection while in the variable permeability-porosity fine-grid model the surfactant oil recovery is greater because both gravity and viscous displacement contribute. We also present a study using our in-house numerical simulator for dual-porosity, dual-porosity refined matrix, dual-porosity with adjustments for viscous displacement and variable permeability-porosity fine-grid models. Dual-porosity models with matrix refinement and viscous displacement give more incremental oil recoveries than the conventional formulation. Results are also compared with variable permeability-porosity fine-grid and coarse-grid models.

We will explain the reasons and will indicate which model is more reliable. In general the results of this study give an insight into the viability of using surfactant injection in thick carbonate reservoirs both in the pilot and production stage.
Viscous Fingering During Non-Thermal Heavy Oil Recovery
Authors: Doorwar Shashvat , Mohanty Kishore K.
Published: October 2011

Alkali-surfactant injection after a short waterflood can improve the recovery of very viscous oils of the order of 10,000 cp or above in corefloods. The goal of this research is to understand the pore-scale phenomenon behind these observations. Several secondary and tertiary floods using water, polymer, and alkali-surfactant slugs have been conducted in two-dimensional silicon micromodels to visualize the pore-scale displacement. The viscosity ratio controls the finger structure. As the viscosity ratio increases, the number of growing fingers (or branches) before breakthrough decreases. At large viscosity ratios of 103 or greater, the finger resembles DLA type fractal structures. Fractal dimensions of these structures vary from 1.4 to 1.6; that for DLA is 1.7. Injection of alkaline-surfactant solution after waterflood lowers the interfacial tension and forms oil-in-water emulsion at the sides of previously established water fingers. The tertiary oil recovery due to alkaline-surfactant flood increases with the surface area of the water fingers.
Discrete Modeling of Natural and Hydraulic Fractures in Shale-Gas Reservoirs
Authors: Gong Bin , Qin Guan , Towler Brian F. , Wang Hongyan
Published: October 2011

Interconnections of hydraulic fractures and pre-existing natural fractures provide key channels for shale gas to flow at economic rates. Micro-seismic mapping has proved that the resulting fracture system is much more complex compared to most conventional reservoirs due to the massive multistage, multi-cluster hydraulic fracturing stimulations. It becomes crucially important to develop advanced approaches to model such a complex system to better understand the recovery mechanisms and to optimize stimulation and development plans of shale gas reservoirs.

Recent advances in geological interpretations and micro-seismic mapping enable realistic modeling of hydraulic and pre-existing fracture network. Consequently, it is possible, to certain extent, to represent actual large-scale fracture distribution in reservoir modeling and simulation of shale gas development. In this paper, we apply the Discrete Fracture Modeling (DFM) approach to represent large-scale fractures individually and explicitly. This entails highly constrained unstructured gridding and construction of a connection (transmissibility) list of all neighboring cells. The geo-mechanical impact on micro-fracture system is modeled by "effective media", in which the rock permeability is sensitive to the stress change induced by hydraulic fracturing and pressure drawdown.

Simulations have been performed based on the detailed modeling of an actual shale gas reservoir with considering various mechanisms including adsorption/desorption, matrix-fracture transfer, and non-Darcy effects. Sensitivity studies by varying the production rate, pressure and hydraulic fracture parameters could be onducted to provide guidance on optimizing stimulation and production designs.

We have proposed and implemented an innovative simulation workflow that effectively captures multi-scale and multi-physics flow behavior caused by complex fracture system and geo-mechanical impact. A field-scale case study demonstrates that the proposed workflow certainly improves predictability in development of shale gas reservoirs.
B.A.R.T (Baseline Risk Assessment Tool): A Step Change in Traditional Risk Assessment Techniques for Process Safety and Asset Integrity Management
Authors: Petrone Annamaria , Scataglini Luciano , Fabio Francesco
Published: October 2011

The oil and gas industry has generally recognized, Process Safety and Asset Integrity Management as key drivers for ensuring, throughout Life Cycle of Oil or Gas plant, the ability of assets to perform their functions efficiently, preventing at the same time occurrence of Major Hazards such as fires, explosions and toxic gas releases thus protecting safety and environment and preserving asset value.

Several tools both qualitative and quantitative are available on the Market to support Process Safety and Asset Integrity Management. In early design phases, qualitative tools can be applied for preliminary evaluation of risk consequences while during subsequent project phases, Quantitative Risk Analysis (QRA) can be performed. However the above mentioned techniques have several shortcomings: QRA is a powerful design tool but can't give credit to operational controls, while qualitative risk analysis does not properly consider technical and process information.

This paper describes an innovative risk screening methodology for evaluating hazards and establishing priorities for risk reduction, supported by dedicated software: B.A.R.T (BAseline Risk assessment Tool) represents a step change in traditional techniques since combines simplified quantitative risk assessment methodology with bow-tie model to identify and assess potential hazards and risks, from upstream onshore/offshore process and activities. The sequence of any major incident is analyzed from identification of primary root causes up to determination of potential effects and impacts. Therefore, all existent safety barriers are identified and their prevention and mitigation risk reduction contributes included in the analysis. BART allows systematic monitoring of all major incident risks through prioritization and selection of effective control measures able to reduce likelihood and/or consequences of current risks.

In the paper methodology and rationale behind the tool are described through a real case application on an existing onshore Oil & Gas installation; main findings are highlighted and positively compared with alternative approaches.
Managing Large Enrollments: Plans to Ensure Students Receive a Quality Education
Authors: Schrader Susan , Todd Burt , Getty John
Published: October 2011

Much has been written about the current and future need for employees in the oil and gas industry. As the price of oil continues to climb again, prospects for a student graduating with a petroleum engineering degree look encouraging. This is helping to encourage high school students to consider studying petroleum engineering at the university level. However, the structure of many university systems and the lack of petroleum engineering programs make it difficult for the universities to ramp up to meet this surging enrollment. As a school experiencing record numbers, Montana Tech is experimenting with ways to manage enrollment, ensure quality and provide well trained students to enter the workforce.

A number of measures designed to manage enrollment and ensure quality have been either implemented or are in the proposal stage. The implemented measures include a new minimum GPA requirement on transfer students, the development of a pre-engineering program, the development of an anti-cheating policy, the enforcement of a 19 credit hour per semester rule, and a search for additional faculty. Proposed measures include allowing students only two attempts to pass courses in their major and establishing a common curriculum for incoming first year engineering students, after which they would apply to the petroleum department. An enrollment cap is proposed as a final measure to be considered after the effects of the above methods are evaluated.

Data currently being collected include class sizes, number of transfer students, class GPA's, and faculty student ratio. Preliminary observations show that some of the implemented measures are having an effect, as they indicate a stabilization of enrollment numbers and a better distribution of class grades.

Many of the institutions that offer a petroleum engineering degree are facing the same enrollment issues. The evaluation of these methods may lead to approaches that can be applied at other institutions, allowing for petroleum education to better able meet the needs of the industry.
Modeling of Multi-Component Flow in Porous Media with Arbitrary Phase Changes
Authors: Voskov D. V.
Published: October 2011

I present a novel computational framework for simulating flow in porous media for mixtures having an arbitrary number of phases. This framework is designed to keep a unified computational structure for different nonlinear formulations and complex physical models. That includes generic phase appearance/disappearance treatment, efficient linear solver typical for mixed types of unknowns, finite volume discretization using flexible spatial stencil etc. The behavior of components in any phase is computed using mixed phase equilibrium assumptions. This type of simulation is very important for modeling of natural and industrial processes, such as development of natural hydrocarbon resources, including gas-hydrates, CO2 injection into hydrocarbon reservoirs and saline aquifers, and for modeling of thermal processes. In this framework I use a Fully Implicit (FI) time approximation with general extension to the Adaptive Implicit Method (AIM) using flexible algebraic reduction. The framework is built on top of an Automatic Differentiation with Expression Templates Library (ADETL) which generates the corresponding derivatives for any nonlinear relation and helps to construct Jacobian matrix for the nonlinear solver. Phase behavior for the new framework is calculated using Compositional Space Parameterization (CSP) approach, which helps to improve both efficiency and robustness of the standard Equation of State (EoS) computations. Within this simulation framework, the nonlinear behavior of different variable sets, including both natural and mass-type variables is investigated. The general extension of two-phase variable substitution is used to handle the phase appearance and disappearance for systems with arbitrary numbers of phases. Examples will be presented including different types of CO2 injection in a hydrocarbon reservoir, such as miscible and immiscible two-phase CO2 injection, thermal injection of CO2+steam (three-phase), and cold CO2 injection (three phase with the second liquid CO2-rich phase).
Fuel Formation During In-Situ Combustion of Heavy Oil
Authors: Hascakir B. , Ross C. M. , Castanier L. M. , Kovscek A. R.
Published: October 2011

In-situ combustion (ISC) is a successful method with great potential for the production of heavy oil. Application of ISC is limited, however, because the process is complex and not well understood. A significant open question for ISC is the formation of coke or "fuel" in correct quantities that is sufficiently reactive such that combustion is sustained. We study ISC from a laboratory perspective in one-meter long combustion tubes that allow monitoring of the progress of the combustion front using X-ray computed tomography (CT). Two crude oils with API gravities of 12 and 9 are studied. Images of oil movement and banking in situ are obtained through appropriate analysis of the spatially and temporally varying CT numbers. Combustion tube runs are quenched prior to front breakthrough at the production end thereby permitting a post mortem analysis of combustion products and in particular of the fuel (coke and coke-like residues) just downstream of the combustion front. Fuel is analyzed using both scanning electron microscopy (SEM) and X-ray photoelectron spectroscopy (XPS). XPS and SEM results are useful to identify the shape, texture, and elemental composition of fuel in the X-ray CT images. The SEM and XPS results aid in differentiation among combustion tube results with significant and negligible amounts of clay minerals. Initial results indicate that clays increase the surface area of fuel deposits formed and this aids combustion. Additionally, comparisons are made of coke-like residues formed during experiments under an inert nitrogen atmosphere and coke-like residues from in-situ combustion. Study results contribute to an improved mechanistic understanding of ISC, fuel formation, and the role of mineral substrates in aiding or impeding combustion. CT imaging permits inference of the width and movement of the fuel zone in situ.
Long and Stuck E-Line - Probable Root Cause Failure Analysis and Fishing Success Story
Authors: Abdul Razak M. Hairi , Azhar M. , Samsu M.
Published: October 2011

Angsi field is one of the major oil and gas producers in offshore Peninsular Malaysia. Highly deviated wells with average depth of 3500 meters represent of about 70% of total wells in Angsi. Perforation and mechanical water shut-off with bridge plug using E-line are common in this type of wells. E-line tractor will be used to run in hole whenever the operator faced difficulties to descend further into target depth. In one instance on such operation, a bridge plug was set at 4900m-MDTHF, while POOH, the E-line stucked. A signal was sent to disconnect the BHA electronically, but failed. Simultaneously, THP slowly built up to 800 psi, an indication that the bridge plug was either not properly set or unset. After exhausting all available options, the E-line cable was cut at BOP with 4860 meters of cable left in hole. Later, braided line open hole fishing operation was started using 3/16 in cable. Set of specially fabricated cable cutter, weight bar and fishing tool was used to compliment the complex work program. At the end, the entire 4860 meters of cable fish was successfully recovered. The E-line cable was sent to base to establish the root cause for the operation upset. This paper details the overall E-line post mortem and diagnostic, fishing work program, the special fishing tool that the field operator and braided line contractor fabricated specifically for this job, well control and project lessons learned.
Surface Area and Pore-Size Distribution in Clays and Shales
Authors: Kuila Utpalendu , Prasad Manika
Published: October 2011

One of the biggest challenges in estimating transport and storage properties of shales is a lack of understanding of their complete pore size distributions. Shale matrix has predominantly micro (pores less than 2 nm diameter) to meso-pores (pores with 2-50 nm diameter). These small pores in shale matrix are mainly associated with clay minerals and organic matter. Thus, comprehending the controls of clays and organic matter on the pore-size distribution is critical to understanding the shale pore network. Historically mercury intrusion techniques are used for pore-size analysis of conventional reservoirs. However, for unconventional shale reservoirs, very high pressures (> 60,000 psi) would be required for mercury to access the full pore-structure which has potential pitfalls. Nitrogen gas adsorption techniques can be used to characterize materials dominated by micro and mesopores (2-50 nm). A limitation of this techniques is that it fails to measure large pores (diameter >300 nm). In this study, we have used a combination of nitrogen gas adsorption and mercury intrusion to study the spectrum of pore-sizes in shales and clays.

Our results on pure clay minerals show that (i) clays have a mulit-scale pore-structure at different dimensions, (ii) Micropores are associated with montmorillonite clays but not with kaolinite, (iii) compaction results in decrease in pore volume and reduction of pore-size in the macropores of the clays while the micropores are shielded from the effect of compaction, and (iv) in natural shales, mineralogy controls the pore-size distributions for shales and presence of micropores in natural shales can be correlated with the dominance of illite-smectite type of clays in the rock.
New Algorithms and Integrated Workflow for Tight Gas and Shale Completions
Authors: Cipolla C. , Weng X. , Onda H. , Nadaraja T. , Ganguly U. , Malpani R.
Published: October 2011

Multi-stage stimulation has become the norm for unconventional reservoir development. How many fracture treatment stages and perforation clusters are optimal? What is the ideal spacing between perforation clusters? Where is the best location for each fracture treatment stage? These are critical and difficult questions to answer when designing completions for tight gas and shale reservoirs and the approach to answering these questions can differ considerably for vertical and horizontal wells in different lithologies. In the past, optimizing the number and location of fracture treatment stages has been primarily a manual, time intensive process, resulting in a "cookie cutter" approach that may not properly account for vertical and lateral heterogeneity. This paper details new algorithms and an integrated workflow that could improve fracture treatment staging in both vertical and horizontal wells.

The primary obstacles to optimizing completions in tight gas and shale reservoirs have been the absence of hydraulic fracture models that properly simulate complex fracture propagation which is common in many reservoirs, efficient methods to create discrete reservoir simulation grids to rigorously model the hydrocarbon production from complex hydraulic fractures, automated fracture treatment staging algorithms, and the ability to efficiently integrate microseismic mapping measurements with geological and geophysical data. One of these obstacles has been overcome with the recent development of complex hydraulic fracture models (Meyer and Bazan, 2011, Weng et al., 2011, Xu et al., 2010). However, the remaining obstacles are just now being addressed.

Algorithms for efficient and rigorous design of multi-stage completions are detailed in the paper. Separate staging algorithms have been developed for vertical and horizontal wells that utilize detailed stress, rock mechanical, and image measurements (i.e. - natural fracture identification) to select stage intervals and perforation locations. The staging algorithms incorporate "fit-for-purpose" hydraulic fracture models ranging from standard planar pseudo 3D models to newly developed complex fracture models, depending on the environment. The algorithms are seamlessly integrated with microseismic measurements, a common Earth Model, and automated routines to discretely grid the complex fracture geometry for reservoir simulation. A common software platform enables the efficient utilization of multiple data sources from multiple disciplines. The application of the newly developed algorithms and integrated workflow is illustrated using examples from tight gas and shale reservoirs.
Improved Precision Magnetic Resonance Acquisition: Application to Shale Evaluation
Authors: Hook Peter , Fairhurst David , Rylander Erik , Badry Rob , Bachman Nate , Crary Steve , Chatawanich Kirk , Taylor Tim
Published: October 2011

Traditional magnetic resonance (MR) acquisition modes tend to focus on the hydrocarbons found in high-porosity permeability rocks. This requires acquisition optimized for longer relaxation times (T1 and T2). Interest in shale resources (gas and oil) has resulted in a reexamination of MR acquisition sequences. Shale hydrocarbon resources are usually in rocks with very fast relaxation times for which traditional application schemes are not optimal.

MR acquisition sequences always involve tradeoffs. Modifying current acquisition schemes to improve precision involved increasing the number of short wait-time sequences. Analytical and Monte Carlo modeling were used to evaluate the tradeoffs between different options. The effect of the inversion parameters on the results was also studied to determine the optimal acquisition sequence and processing parameters for shale resources.

The improved precision from this acquisition is demonstrated with field data. Case studies demonstrate how the improved precision of the MR measurement, combined with other logs, provides a better estimate of the organic or kerogen content of the formation; this is particularly useful in areas where correlations to density or other logs have not yet been developed. High-precision MR pore size information in pilot wells is used to highlight the best layers for horizontal wellbore placement.
A Resident's View of Urban Operations
Authors: Fanchi John R. , Fanchi Christopher J.
Published: October 2011

Gas shales are an increasingly important source of natural gas found around the world. They can extend under population centers and require urban operations. The public perception of gas shale development operations can have an impact on the regulatory environment. The purpose of this paper is to report on the public perception of issues associated with urban operations in the Barnett Shale development area.
Geochemical Oil Fingerprinting – Implications for Production Allocations at Prudhoe Bay Field, Alaska
Authors: Schafer Daniel , Bommarito Olivia , Cooper Katrina , McCaffrey Mark , Meixueiro Paulina , Mower Matt
Published: October 2011

The Prudhoe Bay Field has been producing for more than 30 years with the majority of the production derived from the Ivishak sandstone, and a lesser amount coming from the structurally shallower and stratigraphically younger Sag River sandstone. The reservoir properties of the Sag River are dramatically lower quality than those of the Ivishak with respect to thickness, porosity, permeability, and deliverability. The far superior Ivishak dominates total flow into the wellbore when commingled completions exist; however, since total flow is the sum of oil plus water, the Ivishak does not necessarily dominate oil production in any given well. Within individual wells, proper allocation of commingled production from the Ivishak and Sag River is necessary for well optimization, but such allocation can present a technical challenge. Production logging (PPROF) can assist in production allocation; however, production logging is very costly, sometimes yields ambiguous or even erroneous results, and causes the well to be shut-in while logging setup occurs resulting in deferred production. Geochemistry-based allocation of commingled production (i.e., oil fingerprinting) is far less expensive (~1% the cost of production logging) and is proving to be very reliable for zonal allocations where Sag River and Ivishak perforations exist. The successful application of the geochemical allocation method relies on the availability of pure Sag River and Ivishak "end-member" oils from nearby wells to form the calibration standards for the geochemical methodology. This paper presents examples of the success and limitations encountered while attempting to implement this cost-effective geochemical allocation method.
New Cold Production Technique for Heavy Oil with Strong Bottom Water Drive
Authors: Qin Wenting , Wojtanowicz Andrew K. , White Christopher D.
Published: October 2011

Few heavy oil reservoirs with strong bottom water drives have been developed successfully, because severe water coning causes low ultimate recovery, low well productivity, and high water production. In these reservoirs, thermal and gravity-assisted methods that could improve recovery are perceived economically unfavorable or technologically infeasible. In this paper, we propose a new cold production technique, called Bilateral Water Sink (BWS), to meet those challenges.

The BWS method suppresses water cresting by producing oil and water simultaneously from bilateral horizontal wells completed in the oil and water zones separately. Unlike conventional horizontal well production, where water crest cause water to bypass oil, making the water drive mechanism ineffective; BWS prevents water cresting by altering the potential distribution in the near-well area. With cresting suppressed, the top lateral well's production stream is water-free, and water drives the oil from the edges of the well drainage area to the well, resulting in high ultimate recovery. By exploiting the natural reservoir energy of the bottom water drive, BWS becomes economically, technically, and environmentally appealing – especially for offshore where cold production is the only option and oil-water separation is a problem.

In this paper, new analytical models are derived to design the water and oil rates for BWS and to quantify the BWS's effect of avoiding water cresting and improving oil recovery. The analytical models are verified with numerical simulations. The BWS technique is also theoretically demonstrated using data from actual oilfield. The results show a considerable increase of oil recovery from less than 15 percent for conventional horizontal well to over 40 percent for BWS well.
What Does Microseismicity Tell Us About Hydraulic Fracturing?
Authors: Maxwell S. C. , Cipolla C.
Published: October 2011

Interpreting hydraulic fracture geometry isn't the only proven value application of microseismic imaging. With careful geophysical analysis, the microseismic deformation can also be determined in terms of the fracture strain that results in the source of the observed microseismic signals. The microseismic strain or deformation is potentially of interest, since the deformation associated with the hydraulic fracture controls the fracture dilation and complexity and ultimately the effectiveness of the stimulation. However, evidence is presented here which points to the microseismic being primarily a fast, shearing deformation in contrast to the relatively slow and tensile hydraulic fracture growth. Comparing the deformation energy balance between the recorded microseismic and the hydraulic fracture indicates that the microseismic is a very small component of total deformation. The majority of the fracture deformation is aseismic, beyond what is captured with conventional microseismic monitoring.

The microseismic and hydraulic fracture deformations can be rationalized through a geomechanical model that honors the fracture mechanics and mass balance to simulate fracture growth. A workflow is presented that describes calibrating a geomechanical model using the location, timing and strains of the recorded microseismic to match the modeled interaction between the hydraulic fracture and pre-existing fractures. A rock physics model is also required to define synthetic microseismic data from the geomechanical model, for comparison with the observed microseismic data. The simplest form of calibration is a qualitative match between the relative microseismic density of either number of events or source strength. However, more advanced quantitative matches can also be made between the simulated and monitored microseismicity, by matching the microseismic displacements and mechanisms with the additional constraint of matching the energy balance. Through such a calibrated geomechanical model, the interrelation between stress, fractures, and injected fluid can be examined and used to characterize the hydraulic fracture growth. The validated hydraulic fracture model can then be incorporated into a reservoir simulator to ultimately predict the associated production characteristics. Therefore, beyond hydraulic fracture geometry, microseismic source deformation can be used to constrain a geomechanical model of the hydraulic fracture growth and thereby help describe the overall effectiveness of the stimulation.
Gas Permeability of Shale
Authors: Sakhaee-Pour A. , Bryant Steven L.
Published: October 2011

The permeability is one of the most fundamental properties of any reservoir rock required for modeling hydrocarbon production. However, the shale permeability has not yet been fully understood because of the complexities involved in modeling flow through nanoscale throats. Here, we analyze the effects of adsorbed layers of CH4 and of gas slippage at pore walls on the flow behavior in individual conduits of simple geometry and in networks of such conduits. The network is based on the scanning electron microscopy image and drainage experiment of shale. To represent the effect of adsorbed gas, the effective size of each throat in the network depends on the pressure. The hydraulic conductance of each throat is determined based on the Knudsen number (Kn) criterion. The combined effects of adsorption and slip depend strongly on pressure and on conduit diameter. The results indicate that laboratory measurements made with N2 at ambient temperature and 5 MPa pressure, which is typical for transient pulse decay method, overestimate the gas permeability at early life of production by a factor of 5. This ratio increases if the measurement is run at ambient condition since the low pressure enhances the slippage and reduces the thickness of adsorbed layer. Moreover, the permeability increases nonlinearly as the in-situ pressure decreases during production. This effect contributes to mitigating the decline in production rate of shale gas wells.
Use of Pickett Plots for Evaluation of Shale Gas Formations
Authors: Yu Guang , Aguilera Roberto
Published: October 2011

A practical method, based on the pattern recognition approach used in Pickett plots, is presented for preliminary yet accurate quantitative evaluation of shale gas formations. The method is inspired by a quick-evaluation, time-tested methodology developed by Passey et al. (1990) for shales, which utilizes primarily sonic and resistivity logs. In Passey et al. method the sonic and resistivity logs are overlain in such a way that the curves track each other in fine-grained non-source rocks. Separation of the curves indicates the presence of organic-rich intervals.

The Pickett method presented in this study reproduces data published by Passey et al. with coefficients of determination (R2) greater than 0.99 for cases related to sandstones, limestones, dolomites and shales. As Pickett plots have been used thousands of times in the past for evaluation of the first 3 mentioned lithologies, this paper concentrates primarily on the evaluation of shale gas reservoirs. The advantage of the proposed Pickett plot for shale gas formations is that it allows quick estimates of water saturation, total organic carbon, and under favorable conditions, estimates of fracture intensity and diffusion. The objective of the proposed approximate approach, however, is not to replace detailed petrophysical and thermal maturity studies but to provide quick and accurate evaluations of shale gas formations.

It is concluded that Pickett plots provide a powerful practical tool for quick evaluation of shale gas formations. Examples of applications and comparisons with previously published interpretations are presented in detail.
Impact of Reservoir Permeability on Flowing Sandface Temperatures; Dimensionless Analysis
Authors: App J. F. , Yoshioka K.
Published: October 2011

Layer flow contributions are increasingly being quantified through the analysis of measured sandface flowing temperatures. It is commonly known that the maximum temperature change is affected by the magnitude of the drawdown and the Joule-Thomson expansion coefficient of the fluid. Another parameter which strongly impacts layer sandface flowing temperatures is the layer permeability. Aside from determining the drawdown, the layer permeability also affects the ratio of heat transfer by convection to conduction within a reservoir. The impact of permeability can be represented by the Peclet number, which is a dimensionless quantity representing the ratio of heat transfer by convection to conduction. The Peclet number is directly proportional to reservoir permeability. Through dimensionless analysis it will be shown that for a given drawdown (based on a dimensionless Joule-Thomson expansion coefficient, JTD) the temperature change diminishes at low Peclet numbers and increases at high Peclet numbers. This implies that for low permeability reservoirs such as shale gas or tight oil, the temperature changes will be minimal (less than 0.1 °F) despite the large drawdowns in many instances. Dimensionless analysis is performed for both steady-state and transient thermal models. Results from multi-layer, transient simulations illustrate the ability to identify contrasting permeability layers based upon the Peclet number effect.
An Integrated Workflow for Reservoir Modeling and Flow Simulation of the Nikanassin Tight Gas Reservoir in the Western Canada Sedimentary Basin
Authors: Deng Hui , Aguilera Roberto , Settari Antonin
Published: October 2011

This paper presents an innovative workflow for characterization and reservoir simulation of the tight gas Nikanassin Group in the Western Canada Sedimentary Basin. Petrographic studies of the Nikanassin Group show the presence of (1) intergranular, (2) microfracture + slot, and (3) isolated (non effective) porosities. These porosities are handled with a mathematical triple porosity model for improved petrophysical analysis of the Nikanassin Group. Determination of pore throat apertures (rp35) facilitates facies mapping for reservoir simulation purposes. Numerical well testing of hydraulically fractured wells provides a way of tuning the static model with dynamic well testing information. In the case of open uncemented fractures and slots, numerical well testing indicates that the reduction of in-situ permeability can be more than two orders of magnitude. On the other hand in the case of partially cemented fractures and slots the reduction in permeability might be negligible. The approach permits an efficient representation of hydraulic fractures using transmissibility multipliers for the full field simulation of commingled tight reservoirs with multi-wells and multi-stage fractures.

The result is a sound full field simulation model that permits a reasonable match of production and pressure histories, and forecasting of gas recovery under different well-spacing and depletion scenarios. As most Nikanassin tight gas wells are completed commingled, this research develops a procedure for production allocation of individual contributing formations.

The study shows that there is a very large gas potential in the Nikanassin Group, particularly in the Lower Monteith Formation that can be exploited by reducing significantly the well spacing. The finding is significant as the tight gas Nikanassin Group extends for more than 15,000 km2 within Alberta and British Columbia, which suggests the potential for drilling thousands of wells in the region.