bluuebunny/crossref_metadata_2025 huggingface dataset:
Using Data-Driven Analytics to Assess the Impact of Design Parameters on Production from Shale
Authors: Esmaili S. , Mohaghegh S. D.
Published: June 2014

The importance of production from Shale and its impact on the total US energy equation has focused much attention on this prolific source of hydrocarbon. Consequently, research related to unconventional reservoirs has increased significantly in order to better understand the inherent complexities of their behavior.

Analytical, numerical and statistical analyses have been applied to large multi-variable data set from Shale assets with different degrees of success. The notion that shale is a "statistical play" may be attributed to the fact that many of our preconceived notions on storage and flow mechanisms in shale are not supported by facts. Therefore, we set out to examine the possibility of learning from the data in order to be able to answer some of the questions that rise during the production process. Data Driven Analytics, having roots in pattern recognition and machine learning, have proven to be capable of extracting useful information from large data sets and are extensively used in many industries. Their application to multi-variable data sets from Shale assets, in order to extract understandable structure in the data, is the subject of the work being presented here.

This paper presents a Data Driven Analytics study of design parameters such as well trajectories, completion, and hydraulic fracturing variables for a large number of horizontal wells in Marcellus Shale. The data set from the Shale assets is so complex that use of conventional statistical analysis does not results in understandable trends and patterns. On the other hand, when advanced pattern recognition tools are used, certain (previously hidden) patterns emerges from the data with unmistakable trends.

In this article impact of parameters such as up-dip versus down dip deviation of wells, stimulated lateral length and cluster spacing, etc. on production from wells in a Shale asset is analyzed using an advance pattern recognition algorithm. The analyses are performed using production from multiple time intervals throughout the life of wells.
Gas Injection Rate Needed for SAG Foam Processes to Overcome Gravity Override
Authors: Boeije C. S. , Rossen W. R.
Published: June 2014

Gravity override is a severe problem in gas-injection enhanced-oil-recovery processes, especially in relatively homogeneous formations. Foam can reduce gravity override. Shan and Rossen (2004) show that the best foam process for overcoming gravity override is one of injecting a large slug of surfactant followed by a large slug of gas, injected at constant, maximum-allowable injection pressure. This process works because foam collapses near the injection well, giving good injectivity simultaneously with mobility control at the leading edge of the gas bank. The supply of gas that would be needed to maintain constant injection pressure is a concern for EOR processes where gas is produced industrially or from a separations plant with limited capacity: the available gas stream may not be sufficient for the optimal process.

We show that for such a process, the pressure drop across the foam bank back to the injection well, at fixed injection rate, is nearly constant as the foam bank propagates radially outward. From this result, one can derive a simple formula to predict the rate of gas injection required for each of two limiting cases:

an extremely strong foam at the foam front, many times more viscous than the fluids it displaces. In this case, the rate of gas injection required to maintain constant injection pressure is nearly constant, but injection rate is low. a foam just strong enough to maintain mobility control at its leading edge. In this case injection rate required to maintain constant injection pressure increases steeply with time.

Using the formulae provides a quick initial estimate of how gas injection rate must vary over the duration of the EOR process to maintain an optimal process. In addition, we illustrate how one would determine the properties of a foam that would fit the available gas stream. This criterion then could guide the development of a surfactant formulation with these properties.
Gas-Injection Rate Needed for SAG Foam Processes To Overcome Gravity Override
Authors: Boeije C.S.. S. , Rossen W.R.. R.
Published: June 2014

Gravity override is a severe problem in gas-injection enhanced-oil-recovery (EOR) processes, especially in relatively homogeneous formations. Foam can reduce gravity override. Shan and Rossen (2004) show that the best foam process for overcoming gravity override is one of injecting a large slug of surfactant followed by a large slug of gas, injected at constant, maximum-allowable injection pressure. This process works because foam collapses near the injection well, giving good injectivity simultaneously with mobility control at the leading edge of the gas bank. The supply of gas that would be needed to maintain constant injection pressure is a concern for EOR processes in which gas is produced industrially or from a separations plant with limited capacity: The available gas stream may not be sufficient for the optimal process.

We show that for such a process, the pressure drop across the foam bank back to the injection well, at fixed injection rate, is nearly constant as the foam bank propagates radially outward. From this result, one can derive a simple formula to predict the rate of gas injection required for each of two limiting cases:

An extremely strong foam at the foam front, many times more viscous than the fluids it displaces. In this case, the rate of gas injection required to maintain constant injection pressure is nearly constant, but injection rate is low. A foam just strong enough to maintain mobility control at its leading edge. In this case, injection rate required to maintain constant injection pressure increases steeply with time.

Use of the formulae provides a quick initial estimate of how gas-injection rate must vary over the duration of the EOR process to maintain an optimal process. The fit to simulations of surfactant-alternating-gas (SAG) foam-injection rate in a five-spot pattern is remarkably good, especially for strong foam, given the simplicity of the model. In addition, we illustrate how one would determine the properties of a foam that would fit the available gas stream. This criterion then could guide the development of a surfactant formulation with these properties.
Novel Electro-Hydraulic Intelligent Firing Head for Tubing Conveyed Perforating
Authors: Stolboushkin Eugene , Zuklic Steve , Peterson Rick , Stretton John
Published: June 2014

Existing pressure-sensitive firing heads are either hydraulic or electronic. Hydraulic firing heads have the advantage of simplicity and cost. In addition, hydraulic firing heads do not have batteries and can, therefore, remain downhole for several months before functioning. This enables the operator to utilize their assets and equipment more economically. Electronic firing heads, however, enable operations in small pressure margin wells and allow for more advanced completion equipment and services.

The newly-developed electro-hydraulic firing head combines the long downhole life of a hydraulic firing head with the capabilities of an electronic firing head. An electronic module is programmed at surface to respond only to a pre-programmed pressure signature. Upon detecting this signature, the electronic module activates the hydraulic firing mechanism, initiating the perforating guns below.

This hybrid design incorporates safety features that were previously unique to each type of firing head. The hydraulic firing mechanism, which uses a percussion detonator, eliminates the need for electronic detonators that are sensitive to electro-magnetic interference (EMI) caused by rigsite communications devices. Additionally, this mechanism must have several thousand PSI to function, making surface detonation impossible. The electronics module prevents the firing head from functioning from an unintended overpressure of the wellbore, greatly reducing the possibility of firing off-depth.

This paper will discuss the design, development, and testing of this firing head from a mechanical and electrical engineering point of view, as well as the operational reliability, safety, and human interface features included in the design. In addition, it will discuss the test plan to qualify the tool for reliable and safe operations at up to 30,000 psi at 400ºF, as well as the test results.
Methodological Approach for Optimization of Completion Practices in Mature Carbonate Fields
Authors: Babaniyazov A. , Jackson C. H.
Published: June 2014

Technology advances, coupled with favorable commodity prices, have made it possible for operators to revive mature oil fields once considered depleted. This paper intends to illustrate how using existing wellbores to prove development potential and refine completions practices jump started one such revival in the Permian Basin. The team used a methological approach to prioritize projects, optimize stimulations, minimize the impact of wellbore integrity issues, and drive down costs.

Though this paper focuses on work implemented in a mature field environment, any field with a major review of the existing completion strategy can use the methodology outlined.

Technical discussions focus on stimulation optimization techniques and wellbore integrity assurance. The workflows for project prioritization and cost reduction are also addressed.

The methological approach led to reduction of fracture stimulation expenses by fifty %, reduction in rig time, and reduction of contingency cost associated with well integrity. As a result, otherwise uneconomic resources were added and future development opportunities were identified. Various sand-fracturing stimulation placement and diversion techniques were field tested and compared using post-stimulation production results and after-frac radioactive tracers. Despite the savings offered by diversion with ball sealers, isolation using mechanical tools was significantly more effective and justified the additional costs.

Resin-coated sand concentration for flowback control was analyzed and reduced from 50% to 10% based on findings. The team was able to reduce pad volumes and increase sand concentrations resulting in improved fracture conductivities and reduced costs. Field supervisors were trained to analyze net pressure response and adjust pumping schedule on the fly. The well integrity communication and information workflow was implemented, reducing costs and operations downtime. Major workover risks were identified, recorded, and quantified, improving project contingency planning and resource allocation.
Experimental Study of the Swelling Properties of Unconventional Shale Oil and the Effects of Invasion on Compressive Strength
Authors: Emadi Hossein , Soliman Mohamed , Samuel Robello , Ziaja Malgorzata , Moghaddam Rozbeh B. , Hutchison Shannon
Published: June 2014

In the industry as a whole, we are still at the beginning of the learning curve for shale oil drilling operations; however, many shale-oil wells have been drilled in recent years. Drilling through shale-oil formations is very problematic and imposes significant costs to the operators owing to wellbore-stability problems. These problems include, but are not limited to, tight holes, stuck pipe, fishing, sidetracking, and well abandonment. To more efficiently and effectively drill through these formations, we should better understand their properties.

Few experiments have been performed on shale-oil samples to better understand their properties. Most experiments conducted thus far were performed on common shale core samples, which are significantly different from shale oil samples. In this study, we first determined the mineralogy of shale-oil core samples from the Eagle Ford field and then investigated the swelling properties and Cation Exchange Capacity (CEC) of the core samples in the laboratory. Experiments have been conducted with the samples partially submerged in distilled water and potassium-chloride (KCl) brine. Several experiments have been performed using strain gages to measure lateral, axial, and diagonal swelling in both submerged and non-submerged areas.

The results demonstrate that the swelling properties and CEC of the shale oil core samples are different from the common shale core samples. This study proposes the quantification of the shale/fluid properties, the interaction, and the effects of different fluids on rock properties in unconventional reservoirs. This paper presents and documents the differences in the swelling properties between conventional and unconventional shale. The results of the study will help us to more precisely understand unconventional shale oil rock properties and can be used to design a more effective drilling fluid for field applications, as well as more accurately predict the mechanisms of formation failure.
Predictions of the Growth of Multiple Interacting Hydraulic Fractures in Three Dimensions
Authors: Castonguay Stephen T. , Mear Mark E. , Dean Rick H. , Schmidt Joseph H.
Published: June 2014

This paper presents fracture simulations of multiple, interacting, non-planar fractures in three dimensions. The paper provides a short description of the mathematical formulation of the model but the primary focus is on fracture propagation examples and illustrations of how multiple hydraulic fractures interact in three dimensions. The examples which are presented are intended to provide insight into how the number of growing fractures affects fracture shapes, how changes in fluid viscosity can cause fractures to grow together or grow apart, and how limited-entry at the perforations affects the propagation of interacting fractures. The fracture simulator discussed in this paper models the simultaneous growth of non-planar hydraulic fractures in a three-dimensional linear elastic media, and it can also incorporate stress shadows from hydraulic fractures created during earlier fracture stages. The program uses a symmetric Galerkin boundary element method to model fracture shapes and fracture growth, while flow in the fractures is modeled as power-law fluid flow in arbitrary curved channels. The program uses an effective mode-I stress intensity factor to determine which portions of each fracture will propagate and employs mixed-mode stress intensity factors, KI and KII, to determine propagation directions.
Drilling Systems Automation: Current State, Initiatives and Potential Impact
Authors: Macpherson John D. , de Wardt John P. , Florence Fred , Chapman Clinton D. , Zamora Mario , Laing Moray L. , Iversen Fionn P.
Published: June 2014

Drilling automation is the control of the drilling process by automatic means, ultimately reducing human intervention to a minimum. The concept of automating the drilling process has generated considerable interest, yet there is a lack of agreement on exactly what it is, what it entails, and how to implement it. As with industrial automation in the 1990s, the adoption of open standards enabling automation will have a significant impact on the underlying business model. In the oilfield drilling industry, the business model describes the relationship between operator, drilling contractor, service company, and equipment supplier.

The goal of drilling systems automation is to increase productivity and quality, improve personnel safety, and effectively manage risk. Principal drivers of drilling automation include well complexity, data overload, efficiency, repetitive well manufacturing, access to limited expert resources, knowledge transfer due to the exodus of skilled employees, and health, safety and environmental concerns. With so many drivers, and their potential economic benefits, it is understandable that there are many automation related initiatives within the industry.

Drilling through geopressured, possibly erratic lithologies, to a remote and possibly poorly defined target in a safe manner is not a simple task to automate. It is challenging. Drilling automation focuses on the drilling system and drilling operations, which entail combining various sub-systems, including the downhole BHA and its measurement and active components, the drillstring, fluid, and drilling rig and its sub-assemblies. Operations include conventional overbalanced, managed pressure, and underbalanced drilling operations, and their various procedures, such as tripping and making connections.

This paper examines and defines drilling systems automation, its drivers, enablers and barriers, and its current state and goals. In particular, the paper looks at the vision of drilling systems automation, and the role played by open collaborative initiatives among all segments of the drilling industry. Although commitment to automation by the drilling industry appears by many to lag other major industries, there are segments of the drilling industry that have reached a high level of automation on a commercial basis. There is also significant collaboration among interested parties in creating a standardized, open environment for data flow to foster the development of systems automation.
Effect of Concentration on HPAM Retention in Porous Media
Authors: Zhang Guoyin , Seright R. S.
Published: June 2014

This paper investigates the effect of HPAM polymer concentration on retention in porous media using both static and dynamic measurements. Consistent results using these two methods show that different polymer retention behaviors exist in dilute, semidilute and concentrated regions. In both the dilute and concentrated regions, polymer retention is basically concentration-independent. In contrast, in the semidilute region, polymer retention is concentration-dependent. If a porous medium is first contacted sufficiently with dilute polymer solution to satisfy the retention, no significant additional retention occurs during exposure to higher HPAM concentrations. Based on the experimental results, a concentration-related retention mechanism is proposed that considers the orientation of the adsorbed polymer molecules and the interaction between molecular coils in solution. Using this model, we explain why polymer retention does not show much dependence on concentration in the dilute and concentrated regimes. Further, in the semidilute region, we explain how moderate coil interactions lead to mixed adsorbed polymer orientation and magnitude on rock surfaces, and retention becomes concentration-dependent. In field applications of polymer and chemical floods, reduced polymer retention may be achieved by first injecting a low-concentration polymer bank.
The Role of Autonomous Flow Control in SAGD Well Design
Authors: Banerjee Sudiptya , Jobling Robert , Abdelfattah Tarik , Nguyen Hang
Published: June 2014

Steam-assisted gravity drainage (SAGD) has become the de-facto standard for commercial development of heavy oil and bitumen (HO-B) reserves in a significant number of fields. Although SAGD has proved to be a highly effective technique, many uncertainties and unanswered questions still exist, leaving room to improve production and optimize the economics of a SAGD installation. One notable improvement originating from recent field experience is the novel usage of injection/inflow control devices (ICDs) in a conventional SAGD well pair. The use of a properly designed ICD completion is proving beneficial to both steam chamber development as well as improving the inflow profile of the producing well of the SAGD pair.

Work conducted in the Surmont field of Alberta, Canada provided an excellent starting point to optimize flow control improvements to the SAGD process. However, significantly more needs to be added to the discussion to establish best practices for ICD selection and usage and to quantify the benefits gained from using autonomous ICDs in HO-B reservoirs. It is the goal of this paper to provide a useful reference for ICD behavior and theory, selection criteria, the unique role of ICDs in managing steam chamber development, steam fingering control, and management of the subcool temperature (steam trap control). Representative field simulations of Albertan bitumen sand are used as the basis for describing overall trends in the use of flow control in the SAGD process.
The Risk of Using Risk Matrices
Authors: Thomas Philip , Bratvold Reidar B. , Eric Bickel J.
Published: June 2014

The risk matrix (RM) is a widely espoused approach to assess and analyze risks in the oil & gas (O&G) industry. RMs have been implemented throughout that industry and are extensively used in risk-management contexts. This is evidenced by numerous SPE papers documenting RMs as the primary risk management tool. Yet, despite this extensive use, the key question remains to be addressed: Does the use of RMs guide us to make optimal (or even better) risk-management decisions?

We have reviewed 30 SPE papers as well as several risk-management standards that illustrate and discuss the use of RMs in a variety of risk-management contexts, including HSE, financial, and inspection. These papers promote the use of RMs as a "best practice." Unfortunately, they do not discuss alternative methods or the pros and cons of using RMs.

The perceived benefit of the RM is its intuitive appeal and simplicity. RMs are supposedly easy to construct, easy to explain, and easy to score. They even might appear authoritative and intellectually rigorous. Yet, the development of RMs has taken place completely isolated from academic research in decision making and risk management. This paper discusses and illustrates how RMs produce arbitrary decisions and risk-management actions. These problems cannot be overcome because they are inherent in the structure of RMs. In their place, we recommend that O&G professionals rely on risk- and decision-analytic methods that rest on over 300 years of scientific thought and testing.
Investigation of Miscibility Behavior of CO2 rich Hydrocarbon Systems – With Application for Gas Injection EOR
Authors: Lindeloff Niels , Mogensen Kristian , Oil Mærsk , Pedersen Karen Schou , Tybjerg Peter , Noman Rashed
Published: June 2014

The phase behavior of two Middle East reservoir fluids mixed with CO2 has been studied. The experimental work includes quantification of VLLE/LLE behavior studied in a visual high pressure PVT cell.

To investigate the effect of dispersion on slim tube recoveries, experiments were performed using two different tube sizes. One of the reservoir fluids was found to be miscible with CO2 at the reservoir temperature while a liquid-liquid split persisting at high pressure was observed for the other fluid. As the two liquid phases had approximately the same mobility, a high slimtube recovery was seen for the latter fluid despite the liquid-liquid split. EOS models have been developed matching the swelling and slimtube data and confirming the observed VLLE and LLE phase behavior.

The work has led to an improved understanding of how swelling and MMP data for CO2-crude oil systems is to be interpreted. An important observation is that a miscible drive is not always attainable for a reservoir fluid undergoing CO2 gas injection.
A Case Study Using a Remotely Controlled Downhole Valve for Completion Installation
Authors: Oddie Keith , O'Hara John , Paz Luis
Published: June 2014

Offshore platforms and subsea wells often are designed to enable interventions to be performed during the completion phase of the well construction. An example of the above is the deployment of a deep-set plug (as a temporary barrier) to set the production packer and test integrity of the production tubing.

Each intervention has a direct cost due to rig time and the risks mitigation associated with the manual rig-up and testing of the pressure-control equipment addressing health, safety, and environmental challenges becomes a high priority that will consume time during the planning of operations. Operational risk is present due to the mechanical methods used for deployment and retrieval of the plug, and in deviated well designs, this risk will be even more severe due to the implied impact.

Using a case study in Equatorial Guinea, West Africa, this paper demonstrates how barrier provisions with remote open/close technology capabilities enables interventions to be removed from a completion design. The technology described was used in a horizontal subsea producer well drilled to 3,460m, and will illustrate how combining downhole electronic control with a full-bore hydraulically operated barrier valve removes any need for running control lines to surface. Surface applied pressure and time combinations were used to command remote actuation of the valve. The factors that must be considered when determining these commands are also discussed.

The successful field deployment discussed in this case history illustrates how applying remote open/close technology provided the opportunity to challenge conventional completion methodology and was capable of providing significant cost savings as well as simplifying operational strategies.
First Successful Commercial Application of Dual Gradient Drilling in Ultra-Deepwater GOM
Authors: Ziegler Robert , Sabri Mohd Saiful , Idris M Ramdan , Malt Roar , Stave Roger
Published: June 2014

A previous attempt to drill an exploration well in ultra-deepwater in the GoM did not reach its objective due to an inability to maintain a Water Based Mud system light enough to maintain circulation. For the next round of exploration drilling, a system that allowed dynamic management of Annular Friction Loss (AFL) was required in order to stay within the narrow margin between pore and fracture pressure gradients.

Conventional Rotating Control Device (RCD) based Constant Bottom Hole Pressure (CBHP) management systems were not suitable, as no drilling fluid light enough to manage the AFL with an added backpressure could be applied for this campaign.

A "Controlled Annular Mud Level" type DGD system was successfully applied on this well in 2260 m water depth. This method compensates for the annular friction pressure by reducing the riser level according to the circulation pump rate. The system was also used to manage downhole pressure for cementing operations to mitigate losses and ensure good cement integrity with full returns during the cementing operation.

The riser level was decided in the drilling program and adjusted according to PressureWhileDrilling (PWD) Readings. It could also be demonstrated that lowering the riser level increased ROP, whilst raising it again decreased ROP. The sensitivity for kick detection was greatly improved as the effect of rig motion on surface volumes was eliminated.

The paper presents the project approach to deliver results and the technology applied. Results achieved on this well will be discussed, and how to further enhance the technology to other projects and increase the operational envelope of the system.
Application of Sand Control Modeling Software in a Deepwater Multizone Frac Pack: A Case Study
Authors: Zhu Hong , Joseph Kevin , Chok Peter
Published: June 2014

This paper presents sand control software capabilities and modeling considerations for sand control operations. A case study that captures the planning and execution challenges of predicting work string behavior in a two-zone Frac Pack operation in a deepwater well in the Gulf of Mexico will be presented. The integrated sand control software was used to calculate a suitable set-down weight before the main treatment, taking into account the combined effects of ballooning, thermal gradients, buckling and piston effects unique to the single-trip multi-zone tool system deployed. The net weight at the packer as predicted by the modeling software was compared to downhole gauge data collected during the operation. A summary of lessons learned and future enhancements will be discussed as well.
Wettability Alteration with Brine Composition in High Temperature Carbonate Reservoirs
Authors: Chandrasekhar S. , Mohanty K. K.
Published: June 2014

The effect of brine ionic composition on oil recovery was studied for a limestone reservoir rock at a high temperature. Contact angle, imbibition, core flood and ion analysis were used to find the brines that improve oil recovery and the associated mechanisms. Contact angle experiments showed that modified seawater containing Mg2+ and SO42- and diluted seawater change aged oil-wet calcite plates to more water-wet conditions. Seawater with Ca2+, but without Mg2+ or SO42- was unsuccessful in changing calcite wettability. Modified seawater containing Mg2+ and SO42-, and diluted seawater spontaneously imbibe into the originally oil-wet limestone cores. Modified seawater containing extra SO42- and diluted seawater improve oil recovery from 40% OOIP (for formation brine waterflood) to about 80% OOIP in both secondary and tertiary modes. The residual oil saturation to modified brine injection is approximately 20%. Multi ion exchange and mineral dissolution are responsible for desorption of organic acid groups which lead to more water-wet conditions. Further research is needed for scale-up of these mechanisms from cores to reservoirs.
EOR in Tight Oil Reservoirs through Wettability Alteration
Authors: Kathel Prateek , Mohanty Kishore K.
Published: June 2014

In fractured reservoirs, the efficiency of water flood is governed by spontaneous imbibition of water into oil-containing matrix blocks. When the matrix is oil-wet or mixed-wet, little oil can be recovered by imbibition. The objective of this work is to identify chemicals that can be added to the injection water that can induce imbibition into an originally mixed-wet, tight, fractured sandstone reservoir. Several surfactants were evaluated for their aqueous stability at the reservoir temperature and salinity. Contact angles were measured on a clay-rich sandstone. Spontaneous imbibition tests were conducted on the reservoir rocks. It is shown that the use of dilute (0.1 wt %) surfactant solution can alter the wettability from oil-wet towards more water-wet condition on the mineral plates. Incremental oil recovery as high as 68% OOIP is obtained through spontaneous imbibition experiments performed on tight (∼10 µD) oil-wet/mixed-wet sandstone reservoir cores. Parametric studies performed using numerical simulation show that the rate of oil recovery increases with increasing wettability alteration, increasing fracture density, and decreasing oil viscosity.
Autonomous ICD Range 3B Single-Phase Testing
Authors: Least Brandon , Greci Stephen , Wileman Angel , Ufford Adam
Published: June 2014

Reservoir flow control is important for maximizing hydrocarbon production. Traditional in-flow control devices (ICDs) attempt to balance the completion pressure differential with the reservoir pressure differential so that even flow across production zones is maintained. This maximizes oil production by delaying unwanted fluids from breaking through. Unfortunately, when lower viscosity fluids do break through, they take over the well, significantly reducing production of the desired hydrocarbon. This paper describes the design and function of a self-adjusting in-flow control device referred to as an Autonomus Inflow Control Device (AICD). When hydrocarbons are producing from all zones, the AICD will behave as a traditional ICD, balancing flow. However, when low-viscosity (undesired) fluids break through, the AICD chokes them, significantly slowing flow from the zone producing the undesirable fluids. This autonomous function enables the well to continue producing the desired hydrocarbons for a longer time, maximizing total production.

The paper describes the laboratory testing performed to evaluate the performance of a new generation AICD design in field-like conditions. This new generation design is referred to as the Range 3B, and is similar to the original design now referred to as the Range 3A (Least et.al, 2012) in that it is the same size and shape, but it allows for increased flow rates while keeping similar performance ratios. Results from single-phase experimental flow testing with model fluids and crude oil are presented and discussed.

The testing results proved that the AICD could restrict flow from zones producing undesirable fluids. The discussion further shows that if technology such as the new AICD is applied to new well completion designs, total hydrocarbon recovery will be enhanced, providing a significant benefit for production companies and those involved in design and modeling of new well completions.
Hydrocarbon Saturation From Total Organic Carbon Logs Derived From Inelastic and Capture Nuclear Spectroscopy
Authors: Craddock Paul R. , Herron Susan L. , Badry Rob , Swager Lee I. , Grau James A. , Horkowitz John P. , Rose David
Published: June 2014

The accurate determination of formation hydrocarbon or water saturation is an essential step in the petrophysical evaluation of petroleum reservoirs. A novel method has been developed for estimating hydrocarbon saturation directly from a total organic carbon (Corg) log and a porosity log. The method is enabled by the recent development of a pulsed-neutron logging tool that combines inelastic and capture gamma ray spectroscopy measurements to provide a robust and accurate total organic carbon estimate. The method differs from the well-known approach of using carbon-to-oxygen ratios that is most often applied in cased-hole evaluation. The main advantages of this new method are that it does not require knowledge of formation water resistivity, it does not rely on a resistivity model, it does not require an extensive calibration database, and it is largely independent of clay or other lithology effects. Calculations are available to explore uncertainties in the saturation estimates arising from uncertainties in the log inputs. The statistical uncertainty in the estimate of hydrocarbon saturation is as good as 10 saturation units (s.u.) in conventional reservoirs with porosities of 15 p.u. or greater.

The method has been applied to the determination of hydrocarbon saturation in a variety of formations, including bitumen-filled dolomite, heavy oil sand, and shaly sands with both open-hole and cased-hole wells. The method works equally well in formations drilled and logged with either oil- or water-based mud. The saturation estimates have been benchmarked against a combination of conventional and new logging approaches (e.g., resistivity, magnetic resonance, and dielectric logs) and core measurements, with generally excellent agreement among independent determinations. Hydrocarbon saturations can be determined accurately using the method in a number of formation types where conventional methods and models for estimating fluid saturation commonly fail, such as freshwater and unknown water salinity in formations under enhanced oil recovery.

The case studies demonstrate that a Corg log derived from geochemical spectroscopy logs can be used to obtain reliable estimates of hydrocarbon saturation in a wide range of environmental conditions and formations.
Influence of Surface-Treated Nanoparticles on Displacement Patterns During CO2 Injection
Authors: Aminzadeh B. , Chung D. H. , Zhang X. , Bryant S. L. , Huh C. , DiCarlo D. A.
Published: June 2014

We propose a new strategy for carbon storage in which CO2 is injected into a geologic formation after emplacement of brine containing dispersed surface-modified nanoparticles. This strategy increases the sweep efficiency of CO2 storage in aquifers and enhances the aquifer storage security. The most likely mechanism is the generation of nanoparticle stabilized CO2/water foam which securely traps the injected CO2 for long periods of time.

As a consequence of low density and viscosity of CO2 at typical geologic storage conditions, CO2 injection into aquifers suffers from low sweep efficiency which manifests as the gravity override and viscous fingering. Here, we show that nanoparticles can reduce the mobility of the injected CO2 as it displaces brine, and therefore, increase the sweep efficiency. Further we show that displacing the injected CO2 with brine increases residual phase saturations, and therefore enhance the capillary trapping of CO2.

We conducted core flooding experiments in which liquid CO2 was used to displace brine with and without suspended nanoparticles. Sandstone cores with different degrees of heterogeneity were used to capture the effect of heterogeneity on the efficiency of the proposed technique. Saturation distributions and pressure drops were measured in real time with a modified medical CT scanner and pressure transducers. The use of nanoparticles is shown to render about 90% of the injected CO2 immobile and increases the sweep efficiency up to 20% when compared to the base brine case.
Extra-Deep Resistivity Experience in Brazil Geosteering Operations
Authors: Tilsley-Baker Richard , Antonov Yuriy , Martakov Sergey , Maurer Hans-Martin , Mosin Anton , Sviridov Mikhail , Klein Katharine Sandler , Iversen Marianne , Barbosa José Eustáquio , Carneiro Gabriel
Published: June 2014

The relatively recent development of azimuthal resistivity measurements enables proactive geosteering within complex reservoirs. These successful tools are the major contributor to the substantial expansion of horizontal drilling. The tools enable determining the distance (up to 5 m in ideal conditions) and the azimuthal direction to a resistivity boundary. In ideal conditions, the well is inside a high resistivity layer and the shoulder bed is low resistivity, giving geologists warning of approaching adjacent conductive beds. When the tool is in a low resistivity layer, the depth of detection of an adjacent high resistivity layer is much smaller. In these situations, it is often not possible to use the tool for effective geosteering.

An extra-deep resistivity tool has been used for several years in Norway and has been introduced in the Peregrino Field in Brazil. It operates at lower frequencies, has large transmitter-receiver spacings and a depth of detection up to 25 m. This tool was deployed in addition to the conventional directional resistivity instrument.

The new application in Brazil was supported by inversion software (still in development) to enable possible interpretation of the geology within the tool range. The inversion results provide information that can help identify adjacent reservoir layers while in the target zone and measure the thickness of the reservoir layer being drilled.

Examples are presented from one well where the extra-deep resistivity provided early warnings and additional information that helped to steer the well successfully and maximize reservoir coverage. The extra-deep measurements from the tool also provide valuable reservoir understanding and knowledge for future well planning purposes.
Managing Offshore Megaprojects: Success is an Option
Authors: Sterling Gordon H.
Published: June 2014

The success or failure of any offshore oil and gas development project is dependent on effective integration of intelligent processes, deep-seated technical expertise, multiple company and agency interactions and relationships, solid management and vigorous leadership. This is especially true for deepwater oil and gas developments where the costs are high, the schedules are critical, the technologies used are broad-based and deep, and there is heavy involvement of engaged stakeholders. Recent papers and books, with solid support in data and statistics, have shown that less than one-quarter of the international offshore oil and gas development projects have achieved "success" in any meaningful sense of that word. Furthermore, in a few cases, those that do are the beneficiaries of changed economic circumstances that override the real deficiencies. Based on many years of project experience, involving both success and failure, this paper deals with the many elements that create the environment where success is probable and failure is NOT inevitable.
Frequency Distributions of Effective Permeability and Gas Flux in Leaky Wellbores
Authors: Tao Qing , Bryant Steven L. , Checkai Dean A.
Published: June 2014

Using a previously described model, we estimate the effective permeabilities of about 300 wellbores in six different fields that exhibit sustained casing pressure (SCP) or surface casing vent flow (SCVF). Uncertain parameters that affect the estimated permeability, such as the location of the leak source, are accounted for by a Monte-Carlo simulation approach, yielding an expected value of leakage path permeability for each measurement of SCP or SCVF. Characterizing leakage paths can be useful in diagnosing and remediating poor zonal isolation. This can be particularly valuable in quantifying the likelihood that shallow groundwater is being contaminated by operations in deeper formations, such as shale gas production. Analogous leakage paths are a primary risk factor for large-scale geologic storage of anthropogenic CO2. Being able to estimate CO2 fluxes along existing wellbores is required for quantitative risk assessment.

The expected values of estimated permeabilities along most of the leaky wellbores are between 10 µd to 10 md. Using the wellbore permeabilities to estimate the aperture of the leakage pathways, we estimate the capillary pressure and hence the minimum CO2 plume heights required for CO2 to enter the leakage paths. Almost all leakage pathways require very modest plume heights, so capillary effects are unlikely to prevent leakage. We compute worst-case steady CO2 leakage fluxes, finding that over 90% of the fluxes are less than 0.1 ton/m2/yr. The frequency distribution of the effective permeabilities of leaky wellbores is believed to be the most comprehensive compiled to date. It enables quantitative assessment of leakage rates in a risk assessment context, in particular for the hazard of contamination of shallow resources (e.g. groundwater) by CO2 or natural gas.
Conditions for Generating Nanoparticle-Stabilized CO2 Foams in Fracture and Matrix Flow
Authors: Aroonsri Archawin , Worthen Andrew , Hariz Tarek , Johnston Keith , Huh Chun , Bryant Steven
Published: June 2014

Foams used for mobility control in CO2 flooding, and for more secure sequestration of anthropogenic CO2, can be stabilized with nanoparticles, instead of surfactants, bringing some important advantages. The solid nature of the nanoparticles in stabilized foams allows them to withstand the high-temperature reservoir conditions for extended periods of time. They also have more robust stability because of the large adsorption energy required to bring the nanoparticles to the bubble interface.

Silica nanoparticle-stabilized CO2-in-brine foams were generated by the co-injection of CO2 and aqueous nanoparticle dispersion through beadpacks, and through unfractured and fractured sandstone cores. Foam flow in rock matrix and fracture, both through Boise and Berea sandstones, was investigated. The apparent viscosity measured from foam flow in various porous media was also compared with that measured in a capillary tube, installed downstream of beadpacks and cores.

The domain of foam stability and the apparent foam viscosity in beadpacks was first investigated with focus on how the surface wettability of nanoparticles affects the foam generation. A variety of silica nanoparticles without any surface coating and with different coatings were tested, and the concept of hydrophilic/CO2-philic balance (HCB) was found to be very useful in designing surface coatings that provide foams with robust stability. Opaque, white CO2-in-water foams (bubble diameter < 100 µm) were generated with either polyethyleneglycol-coated silica or methylsilyl-modified silica nanoparticles with CO2 densities between 0.2 and 0.9 g/cc. The synergistic interactions at the surface of nanoparticles (bare colloidal silica) and surfactant (caprylamidopropyl betaine) in generating stable CO2 foams were also investigated.

The common and distinct requirements to generate stable CO2 foams with 5-nm silica nanoparticles, in rock matrices and in fractures, were characterized by running foam generation experiments in Boise and Berea sandstone cores. The threshold shear rates for foam generation in matrix and in fracture, both in Boise and Berea sandstones, were characterized. The ability of nanoparticles to generate foams only above a threshold shear rate is advantageous, because high shear rates are associated with high permeability zones and fractures. Reducing CO2 mobility in these zones with foam diverts CO2 into lower permeability regions that still contain unswept oil.
Rate-Time Decline Analysis for Natural Gas Wells with Significant Rock Compressibility Effects
Authors: Zhang Miao , Ayala H. , Luis F.
Published: June 2014

State-of-the-art analysis of production performance of gas wells relies on material balance concepts combined with pseudo-pressure and pseudo-time for rate-time decline analysis and reserve estimations. Customarily, rock compressibility and reservoir pore volume change are either neglected or accounted for by replacing gas compressibility with total compressibility values. In this work, we extend the applicability of a rescaled exponential and density-based decline analysis approach (Ayala and Ye, 2012 and Ayala and Ye, 2013) for the decline analysis of gas systems experiencing significant rock compressibility effects. We formally derive the density-based analytical technique that rigorously captures formation compressibility effects during for the analysis of gas well production data during boundary-dominated-flow (BDF). This formulation enables calculation of correct prediction of well performance with depletion) by incorporating formation compressibility and the change of reservoir pore volume effects, which proves crucially important for high-pressure and/or large-formation-compressibility gas reservoir systems.
Modeling Gas Flow through Hydraulically-Fractured Shale-Gas Reservoirs Involving Molecular-to-Inertial Transport Regimes and Threshold-Pressure Gradient
Authors: Civan Faruk
Published: June 2014

This paper demonstrates that formulation beyond the usual is required for rigorous modeling of flow through hydraulically-fractured shale-gas reservoirs. This challenging task is demonstrated here by considering the transport of gas in nano-permeability shale-gas reservoirs, including absorption, adsorption, pore-confinement, and alteration of gas properties. This leads to significant deviations from the conventional treatment.
Full-Scale Laboratory Study of the Impact of Drilling Fluid Composition and Properties on Penetration Rates in Brazilian Pre-Salt Carbonates
Authors: Curry David , Bland Ron , Lourenco Affonso , Lutes Paul , da Fonseca Carlos Eduardo , de Sa Carlos Henrique , Lomba Rosana
Published: June 2014

Full-scale laboratory drilling tests investigated the drilling performance potential of a number of different drilling fluids in three analogue rocks for the pre-salt formations offshore Brazil: Bonne Terre dolomite, Carthage limestone, and Navajo Gold travertine. High-pressure drilling tests were performed in each of these rocks using a total of nine different drilling fluids, including a synthetic-based fluid used as reference for performance comparison.

There was a consistent ranking of drilling fluids in terms of their penetration rate and mechanical specific energy in all three rocks. Several of the fluids tested showed penetration rates ∼50% higher and mechanical specific energies ∼35% lower than those seen with the baseline synthetic-based fluid. There was no clear correlation between good drilling performance and base fluid, rheology, or suspended solids. There was, however, evidence of a correlation between drilling performance and continuous phase viscosity; drilling performance apparently increased as the continuous phase viscosity decreased. This effect is consistent with a hypothesis that filtrate invasion into the damaged rock can relax so-called chip hold-down forces and thereby reduce their negative impact on the efficiency of the rock destruction process.

The results presented here yielded what is believed to be the first evidence that increasing drilling fluid temperature can lead to an increase in penetration rate and a decrease in mechanical specific energy when all other conditions and operating parameters are held constant.