bluuebunny/crossref_metadata_2025 huggingface dataset:
First Offshore Coiled Tubing Intervention Using a Catenary System in the Gulf of Mexico
Authors: Huerta Juan Martin , Lara Ricardo Ramirez , Marin Marlon , Kowalski Ricardo , Franco Ernesto , Ortega Ruben , Ponce Gabriel , Hernandez Daniel , Ramos Jaime
Published: June 2014

Coiled tubing (CT) operated from a floating anchored vessel (FAV) was developed for well intervention in offshore locations where crane limitations and deck loading constrains imposes various limitations on the ability to perform workover operations. This tailor-made solution involves the operation of a CT unit with the tubing reel located on a FAV and the injector head positioned on the offshore platform. Today, CT operations supported by a FAV are routinely performed in several countries, including Malaysia, Gabon, Tunisia, Brunei, Angola and the North Sea.

The first CT operation supported with a vessel in the Gulf of Mexico was successfully performed in a non-producing well which had been shut-in for nine months due to compatibility issues with the structure for temporary installing service equipment and and the limited availability of jack-up platforms to provide a deck area for positioning CT equipment. As result of this successful operation, a new perspective of CT rigless interventions was adopted in offshore Mexico, thus allowing the operator to improve equipment utilization for both CT units and workover rigs, in order to maximize oil production.

This paper details the analysis, execution and evaluation of the first CT operation from a FAV in offshore Mexico, which includes equipment selection, sea condition and weather-related studies, contingency planning, personnel competency and training requirements, and logistical considerations, among other technical factors that were critical in the implementation of such project. As well, the benefits that were realized by the operator regarding production enhancement and operational cost reduction are covered.
CT Extended Reach: Can We Reach Farther?
Authors: Newman Ken , Kelleher P.E, Patrick , Smalley Ed
Published: June 2014

The ability to perform extended reach operations with coiled tubing (CT) has become increasingly important in recent years as a result of the increased length of horizontal wellbores. Fracturing horizontal wells in stages often requires the use of drillable bridge plugs or sliding sleeves, which are drilled out or slid with CT. As the length of the horizontal section of a wellbore continues to be extended (known as extended reach), the reach of CT also needs to be extended. Drillpipe is able to reach farther than CT due to its ability to rotate (which mitigates sliding friction). The inability of CT to rotate makes extending the reach more challenging.

This paper presents the theory and modeling which helps determine the maximum reach in a horizontal well before helical lockup occurs. It presents a parametric study for an L shaped well which shows the significance of each parameter in extending the reach. A new tapered CT string concept referred to as "Extended Taper™", is presented.
Case Study of New Technology Introduction: Through Tubing Zonal Isolation with an Expandable Plug in Dual Completion Well
Authors: Al-Jasmi Ahmad Kh. , Choudhuri Amit , Desai Sameer Faisal
Published: June 2014

Kuwait Oil Company (KOC) had major issues in resolving problems of controlling water production from long strings in dual 9-5/8" completion wells. An economic process of zonal isolation was being investigated by the Company since conventional process of mobilizing a work over rig is expensive and would also result in loss of production from the short string of the well during the workover job. Many technologies through tubing had been tried earlier but did not succeed in positive isolation on a consistent basis. This was a technology challenge presented to Research and Technology Group for identification of a suitable technology. On review of various technologies, it was decided to pilot trial HIP plug from a service provider in one of the dual completion well of KOC. The pilot trial was planned to test functionality and integrity of the plugging process in isolating the bottom zones of the wells by intervening thru tubing.

This paper would exemplify KOC’s new technology identification process, selection, pilot project execution process, trial validation and determination of success criteria.
Casing Patches Used to Temporarily Shut Off Reservoirs
Authors: Wilczek P. , Oberascher R. , Osmanovic A.
Published: June 2014

Remedial operations on high permeable und underbalanced reservoirs can become risky. Lack of an exact liquid level, tight clearances leading to a high ECD and old unreliable reservoir characteristics can result in a fast liquid loss situation occurring out of view. Good mud properties can handle this issue but an instable filter cake can quickly lead to a situation where the formation will be filled with cement while your secondary liner is still uncemented. This situation is irreversible and in the worst case may even stay unnoticed.

Casing patches, which are thin steel liners tightly pressed against the inside wall of a casing and designed for zonal isolation and casing leak treatment, can be an efficient remedy for these type of problems. Used on perforated reservoirs they provide a stable and reliable temporary barrier during a workover. The reservoir is reopened using conventional perforating guns once the workover is finished. Since the patches are non-invasive, no additional reservoir damage can be expected.

Within the fields of GDF SUEZ Germany Exploration & Production (DExPro) this technique has been used successfully on three wells in 2011. Two of these wells required a secondary liner and one needed to be hydraulically fractured in order to overcome strong reservoir damage. All three had significant issues that made a conventional workover approach risky. The casing patch technology provided reduced contingency in the workover plan and provided an excellent protection of the fragile reservoir environment.
Milling PosiSet Plugs with Coiled Tubing to Remove Zonal Isolation
Authors: Hester J. , Gil C. , Torres M.
Published: June 2014

As part of the old time reservoir strategy to develop the Cusiana field in Colombia, PosiSet Plugs were set on Electric Line with cement on top mainly for Gas Shut Off purposes. In the recent years, it was necessary to remove the isolation to comply with the updated reservoir strategy to produce the lower reservoirs. Instead of a Workover rig intervention for cost optimization, Coiled Tubing was used to mill the cement, mill and push the PosiSet Plug and reestablish access and production of previously isolated zones.

At the beginning there were not many case stories of PosiSet Plug milling worldwide and several difficulties were observed in the first attempts. Milling time was high and not all interventions were successful. However a robust learning curve was created allowing the current removal of PosiSet Plugs without major difficulty in terms of hours. Tools used and operational procedure represents the key points of the implemented strategy.
Isolation of Water Producing Interval in a Horizontal Well Completed with Multistage Fracturing System Using Two CT Inflatable Bridge Plugs
Authors: Burdin K. V. , Mazitov R. N. , Bravkov P. V. , Serikov D. A. , Klimenko V. N. , Zhuk V. , Golovanev A. S. , Potryasov A. A. , Kovalev V. N. , Yunusov R. R.
Published: June 2014

The widespread application of multi-stage fracturing technology in Russia is already known not only due to increase of production rates and increase of recoverable reserves but also due to premature water flooding of some intervals. Several reasons could lead to that result, while, perhaps, the main one is a breakthrough in the aquifers in the process of the fracturing.

Objective of the job given by the client was to isolate water producing interval in a horizontal well completed with 8-stage MSF completion. To determine position of water-flooded zone, coiled tubing production logging tool (PLT) was used. Based on CT logging data 6th frac port of 8-stage MSF completion was found to be water flooded. Moreover, while total production rate of the well was equal to 500 m3/day (data was received during nitrogen lift while logging) with 95% WC, 68% of total production came from 6th frac port.

This article includes detailed study of planning process, complex and unambiguous decision-making aimed at technical and practical challenges, risk assessment and methods to reduce them, the stages of the work and planning in different situations that arise in the process of water shut-off and received lessons learned.
Composite: Is Multi-Plug Milling That Fast?
Authors: Cromer C. M. , Aviles I. , Li N.
Published: June 2014

Multi-stage stimulation by use of composite plugs (CP) for isolation has been in practice for over 15 years in North America. It continues to be a cost effective solution for shale plays requiring hydraulic stimulation of horizontal wells. Currently, there are dozens of plug venders in North America that supplied hundreds of thousands of plugs to the market. In order to perform effectively, plugs must convey down long horizontal wells, deploy at the appropriate depth in a well, hold pressure during a frac, and be removed utilizing conventional wellbore cleanout techniques, which in most areas involve milling with coiled tubing. The milling aspect of designing a plug can be particularly challenging, as it can be difficult to simulate without conducting a full scale test. Additionally, there are many different types of bits or mills to choose from. Thus, testing is required when designing a plug to optimize milling performance. Failure to do so can result in increased milling time and cost, something unacceptable in these tight-economic plays.

Mill out testing during the qualification phase is key to the plug performance in real bottomhole conditions. Multiple plugs are used in a single well that ideally will be milled out sequentially. Thus performing a mill test with only one plug may result in an optimistic view of plug milling. There are several important parameters in evaluating milling performance or millability in a test, including: overall millout time, penetration rate, debris size, and stump size. The millout time per plug in a well is defined as the average time taken to mill through a single plug, starting when the mill contacts the top of the plug and ending when the plug‟s anchoring mechanism gives way. This leaves the bottom part, or stump, un-milled. The shape and size of the stump may significantly affect how the debris is conveyed to the next plug as well as the milling of the next plug. Millout time must calculate as an average of no less than two plugs milled in sequence.

This paper will describe the best practices for determining the millability of a CP in a multiple plug scenario, and show how milling tests can be used to improve the design of a plug and optimize mill selection. This in turn maximizes the chances of successfully and efficiently removing CPs in the multi-zone treatment application, with the overall goal of improving the economics of these wells.
Adaptability of Coiled Tubing Technology Enables Complex Well Abandonment in Gulf of Mexico Inland Waters
Authors: Webb B. , Rudnik A. , Bonin B. , Crider K.
Published: June 2014

An operator drilled an inland waters well in the 1960’s in southern Louisiana. By the time the well was scheduled for plug and abandonment (P&A), the canal had been transformed into wetlands and significant silt had built up around the wellhead, thus increasing the complexity of the abandonment operations. The environmental impact to the wetlands would be minimized by laying mats around the well in preparation for coiled tubing (CT) operations. However, these mats laid out on the soft wetlands would not safely support the excessive weight of the CT unit and reel, so they were rigged up on a barge 125-ft away from the wellhead. A CT drilling tower was used to provide stability to the wellhead stack. The wellbore conditions (11,300 psi MASP and 313 deg F BHT) increased the complexity of this operation further, requiring a very thorough job planning process. A mock rig-up of equipment was performed before mobilizing equipment to location to ensure the stability of the wellhead stack. The CT operations were completed successfully which allowed the operator to complete the decommissioning of the well. This paper presents a case study that demonstrates the adaptability of CT technology to meet the special requirements of well abandonment in the inland waters environment of the Gulf of Mexico.
A History of Gas Lift Valve and Gas Lift Mandrel Damage and Subsequent Retrofit Gas Lift Straddle Installation in Alaska
Authors: Julian J. Y. , Jackson J. C. , White T. M.
Published: June 2014

In Alaska oilfields, non rig tubing repair has become a viable alternative to rig workovers (RWO). Tubing straddles can remediate tubing by casing ("A" annulus) communication at a tremendous savings in areas where rig workover cost is significant. This paper advances the analysis of more than 400 tubing straddles set since 1985. SPE paper 104055 showed that the majority of straddles were installed over damaged gaslift valves and gaslift mandrels. Damage to a gaslift valve can occur when it is eroded (or flow cut) due to fluid unloading of the casing by tubing annulus through the gaslift valve. This leads to tubing by "A" annulus communication which usually requires that the damaged gaslift valve be replaced. However, if the gaslift valve has been flow cut and is not replaced immediately, the gaslift mandrel itself, which is a part of the tubing completion, can be subsequently flow cut, requiring tubing replacement or tubing straddle installation. This paper will update the results of the straddle study on a large gaslifted field to quantify the signifance of the problem. It will not only discuss the history of wells that required a straddle to repair gaslift valve or mandrel damage, but will also analyze wells that only required a gaslift valve replacement to repair tubing communication due to a damaged gaslift valve.

The paper will also describe the use of retrofit gaslift straddles in 3-1/2" thru 7" tubing sizes, including lessons learned. Retrofit gaslift straddles are a subset of tubing straddles. They are particularly attractive in areas where rig workover cost is significant, such as offshore, remote, or arctic locations. Most significantly, the paper will discuss a commercially available barrier gaslift valve, why it is superior to conventional gaslift valves and upcoming installation plans in Alaska to prevent gas lift valve damage and subsequent gaslift mandrel damage.
Collaborative Industry Initiative to Assess Potential Health Effects Related to the Production of Unconventional Resources
Authors: Devlin D. J. , Beatty P. , White R. D. , Naufal Z. , Sarang S. S.
Published: June 2014

Unconventional resources offer many substantial benefits as energy sources and chemical feedstocks. Natural gas is abundant, affordable, clean burning, increases energy security, and provides significant economic benefits at local and national levels. Yet, the rapid increase in production of these resources from unconventional shales using the process of hydraulic fracturing has generated scrutiny by some policymakers and advocates who cite health concerns. The industry, through the American Petroleum Institute (API), is taking steps to assess all legitimate health concerns, communicate our findings, and ensure that public health is adequately protected. API recently formed the Exploration and Production (E&P) Health Issues Group to provide research, scientific analysis, and guidance on health issues regarding Unconventional Resource Production (URP). The Group is particularly focused on community health concerns, including those associated with the compositions of hydraulic fracturing fluid and flowback, aquifer impacts, air emissions, and psycho-social stress related to operations. URP is an industrial activity that carries benefits and potential risks, similar to conventional resources. The risks must be identified, assessed and effectively managed. The work being performed and communicated by this API Group will help to ensure that any potential health risks from production of unconventional resources are identified, evaluated, appropriately communicated, and managed to enhance public confidence and ensure protection of public health.
Fracture Propagation, Fluid Flow, and Geomechanics of Water-Based Hydraulic Fracturing in Shale Gas Systems and Electromagnetic Geophysical Monitoring of Fluid Migration
Authors: Kim Jihoon , Um Evan Schankee , Moridis George J.
Published: June 2014

We investigate fracture propagation induced by hydraulic fracturing with water-injection, using numerical simulation. For full 3D rigorous modeling, we employ a numerical method that can model failure due to tensile and shear stresses, dynamic nonlinear permeability, the dual continuum approach, leak-off in all directions, and thermo-poro-mechanical effects. From the numerical results, fracture propagation is not the same as propagation of the water front, because fracturing is governed by geomechanics, whereas water saturation is determined by fluid flow. At early times, the water saturation front is almost identical to the fracture tip, showing that the fracture is mostly filled with injected water. However, at late times, advance of the water front is retarded, compared to the fracture propagation, yielding a significant gap between the water front and the fracture top, which is filled with reservoir gas. We also find considerable leak-off of water to the reservoir. The inconsistency between the fracture volume and the volume of injected water cannot properly estimate the fracture length, when it is estimated based on the simple assumption that the fracture is fully saturated with injected water. As an example of flow-geomechanical responses, we identify pressure fluctuation under constant water injection, because hydraulic fracturing is itself a set of many failure processes, in which pressure drops every time when failure occurs. The fluctuation decreases as the fracture length grows.

We also study application of electromagnetic (EM) geophysical methods, because the EM geophysical methods are highly sensitive to changes in porosity and pore-fluid properties, such as water injection into gas reservoirs. We employ a 3D finite-element EM geophysical simulator and evaluate the sensitivity of the crosswell EM method for monitoring fluid movements in shaly reservoirs. For the sensitivity evaluation, reservoir models are generated through the coupled flow-geomechanical simulator and are transformed via a rock physics model into electrical conductivity models. It is shown that anomalous conductivity distribution in the resulting models is closely related with injected water saturation but little with newly-created unsaturated fractures. The numerical modeling experiments demonstrate that the crosswell EM method can be highly sensitive to conductivity changes that directly indicate the migration pathways of the injected fluid. Accordingly, the EM method can serve as an effective monitoring tool for distribution of injected water (i.e. migration pathways) during hydraulic fracturing operations.
Fully-Coupled Numerical Evaluations of Multiwell Completion Schemes: The Critical Role of In-Situ Pressure Changes and Well Configuration
Authors: Nagel N. , Sheibani F. , Lee B. , Agharazi A. , Zhang F.
Published: June 2014

The development of many shale plays has been met with significant challenges, including low production rates and rapid production declines, and many ideas and concepts have been tried to address these. Multi-well completions, like ‘Simulfracs’ and ‘Zipper fracs’ for example, have been attempted as a means to increase production, but these have met with only limited success.

The authors have shown in previous work that multi-well completions increase the in-situ stress field around the created hydraulic fractures, which has the effect of stabilizing natural fractures and weakness planes (making them more resistant to shear). Further, the authors have also shown in previous work that the increase in shear from the tip of propagating hydraulic fractures, in a Zipper frac multi-well completion for example, is a complicated factor of well spacing, frac spacing, hydraulic fracture length (for a given well spacing), natural fracture mechanical properties, and in-situ stress.

In this paper, we present the results of a discrete element model numerical study of multi-well completions simulated in a fully hydro-mechanical coupled fashion. Building upon the previous work of the authors and others, the influence of changes in the in-situ pressure are considered in order to more completely understand the mechanical interactions between propagating hydraulic fractures and natural fractures during multi-well completions. The study includes a parametric study of well configuration, in-situ stress conditions, in-situ pressure, and mechanical properties on the ability to enhance natural fracture shear from multi-well completions and increase hydrocarbon production.

The quantitative results of the study provide a direct means to consider when multi-well completions may help increase hydrocarbon production. Further, the results of the study also provide a means to optimize the application and design of multi-well completions as a function of the in-situ stresses, in-situ pressure, the mechanical properties of the natural fractures and weakness planes, and well configuration, which, ultimately, should lead to improved well economics.
Phase Behavior and Minimum Miscibility Pressure in Nanopores
Authors: Teklu Tadesse Weldu , Alharthy Najeeb , Kazemi Hossein , Yin Xiaolong , Graves Ramona M. , AlSumaiti Ali M.
Published: June 2014

Numerous studies indicate that the pressure/volume/temperature (PVT) phase behavior of fluids in large pores (designated “unconfined” space) deviates from phase behavior in nanopores (designated “confined” space). The deviation in confined space has been attributed to the increase in capillary force, electrostatic interactions, van der Waals forces, and fluid structural changes.

In this paper, conventional vapor/liquid equilibrium (VLE) calculations are modified to account for the capillary pressure and the critical-pressure and -temperature shifts in nanopores. The modified VLE is used to study the phase behavior of reservoir fluids in unconventional reservoirs. The multiple-mixing-cell (MMC) algorithm and the modified VLE procedure were used to determine the minimal miscibility pressure (MMP) of a synthetic oil and Bakken oil with carbon dioxide (CO2) and mixtures of CO2 and methane gas.

We show that the bubblepoint pressure, gas/oil interfacial tension (IFT), and MMP are decreased with confinement (nanopores), whereas the upper dewpoint pressure increases and the lower dewpoint pressure decreases.
The Use of Single and Multi-Phase MPD and UBD Techniques on Numerous Wells and Hole Sections Have Made it Possible to Drill the Un-Drillable in Mexico
Authors: Beltran Paredes Juan Carlos , Lupo Cecconi Corrado Pier , Chable Marcos Adrian , Moreno Hermogenes Duno , Bonilla Carlos Andres
Published: June 2014

The first commercial discovery of oil in Mexico took place in 1904, with the Pez-1 well located in the area of Ébano, San Luis Potosí. This well produced 1,500 barrels per day of crude oil. At the time, any well producing one tenth of this production was considered a great findthroughout the world.

Conventional overbalanced techniques were used to drill oil and gas wells in Mexico to control reservoir pressures and the mechanical stability of rocks where different formations intersected. It wasn’t until 1995 that PEMEX began to implement near/underbalanced drilling (UBD) techniques with the primary intent of drilling depleted reservoirs. Later on, managed pressure drilling (MPD) was implemented as a solution in several of the Mexico oil pay zones to overcome operational problems such as fluid losses, differential sticking, and influx events induced not only by the narrow margin operating window, but also the high frictional pressure losses due to increasingly complex wellbore geometries. Years ago, these hole sections were drilled conventionally, but the constant influxes and subsequent partial and/or total losses of circulation during the well control events made feasible alternative techniques mandatory to reach section TD without influx/loss events.

Single and multi-phase MPD techniques are now widely used across most all Mexico fields and have become a standard in well operations, unlike a few years ago when the technology was considered new. These techniques are used effectively to overcome operational problems in high pressure, high temperature (HPHT), high pressure, low temperature (HPLT) and low pressure, high temperature (LPHT) wells in deep reservoirs, delivering success by avoiding NPT and by successfully reaching planned TD.

Today Mexico is encountering a stage of MPD deployment that involves the use of state-of-the-art single andmulti-phase MPD techniques and UBD. Combined with dedicated engineering support, this approach has provided an increased level of safety and performance, and in some cases, allowed realtime formation evaluation through bottomholeprecise bottomhole pressure management with surface backpressure and nitrogen gas injection systems.

This paper summarizes the single and multi-phase MPD and UBD techniques performed on more than 400 complex and diverse hole sections in Mexico oil and gas basins, both exploration and development fields. Highly complex, specialized applications, such as foamed mud and concentric casing nitrogen injection drilling, will also be discussed.
Production Data Analysis of Overpressured Liquid-Rich Shale Reservoirs: Effect of Degree of Undersaturation
Authors: Behmanesh H. , Hamdi H. , Heidari Sureshjani M. , Clarkson C. R.
Published: June 2014

Liquid-rich shale plays (LRS) in North America have recently gained a lot of attention. Commercialization of these plays is now possible due to new technology, such as multi-fractured horizontal wells (MFHW). Along with such developments, there is an increased requirement to develop consistent reservoir-engineering methods to analyze multi-phase production data in such reservoirs. Large drawdowns required to produce these very low permeability formations complicate production analysis due to condensate drop-out near the wellbore or fracture face.

Hydraulically-fractured vertical and horizontal wells completed in tight formations typically exhibit long periods of transient linear flow. This paper discusses a novel production data analysis technique for constant flowing bottomhole pressure (pwf < pdew) wells producing from fractured LRS reservoirs. Our focus in this work is on cases where the initial reservoir pressure is well above the dew point pressure, as occurs in highly-undersaturated portions of the Eagle Ford Formation. A theoretical basis is developed for analysis of the transient linear flow period for these cases, and the effect of initial pressure on well performance is studied. The governing flow equation is linearized using appropriately defined two- phase pseudopressure and pseudotime functions, where the liquid solution analogy can be applied. This approach provides an accurate estimation of the linear flow parameter (xf√k) in multi-phase flow situations. Fine-grid compositional and black oil numerical models are used to validate the results. This work provides a robust analytical framework for production analysis of liquid-rich shale reservoirs as well as practical guidelines for real world applications.
Immediate Gas Production from Shale Gas Wells: A Two-Phase Flowback Model
Authors: Adefidipe O. A. , Dehghanpour H. , Virues C. J.
Published: June 2014

Although existing models for analysing single-phase flowback water production at the onset of flowback in tight oil and gas reservoirs provide estimates of fracture volume, they are not applicable to shale gas reservoirs. This is because flowback data from shale gas wells do not show this single phase region. Instead, they show a surprising trend of immediate gas breakthrough. This paper attempts to (1) understand the fundamental reasons for this early gas breakthrough, (2) develop a representative mathematical model that describes this behaviour and (3) estimate the effective fracture volume and equivalent fracture half-length by history matching the early-time two-phase flowback data.

From the diagnostic plots generated from of rate/pressure data of 8 multi-fractured horizontal wells completed in the Muskwa Formation, the gas-water ratio (GWR) plots indicate the presence of initial free gas in the complex fracture network. This conclusion is backed by the imbibition experiments conducted on shale samples collected from the same formation showing the presence of gas-saturated natural fractures. The linear diffusivity equation is solved for early-time two-phase gas/water flow in the hydraulic fractures. The primary drive mechanism at the onset of flowback is initial free gas expansion within the fracture network. Secondary drive mechanisms considered include fracture water expansion and fracture closure. The driving forces are modeled by an effective compressibility term analogous to the total compressibility in conventional multiphase flow formulations. Also, two-phase water/gas flow is handled by an explicitly determined relative permeability function of time. Eventually a new pseudo-time function is defined to account for the changes in gas properties and relative permeability with time. Rate normalized pseudo-pressure versus pseudo-time plots give a straight line when applied to field data, thus the solution can be used to characterize hydraulic fractures in a manner similar to conventional well testing methods.
A Study of Dynamic and Static Factors That Are Critical to Multi-Well Reservoir Simulation of Liquid Rich Shale Plays
Authors: Miranda Carlos , Yang Huade
Published: June 2014

The development of unconventional resources has increasingly focused in liquid rich systems in the recent years in the USA, due to relatively low natural gas prices and conversely high oil prices. In order to maximize production and optimize the development of these resource plays, adequate modeling of wells and reservoir performance is required. Reservoir simulation has been recognized as one of the most acceptable tools to model the performance of liquid rich shale (LRS) systems. Analytical solutions (DCA, RTA, PTA) exhibit several limitations to properly model the effects of multiphase flow, stress and pressure dependent permeability, condensate banking, flow through hydraulic fractures and stimulated rock volume (SRV) region, etc. on the reservoir performance of LRS plays.

Single well modeling has been extensively used to model well and reservoir performance from shale plays, but multi-well or sector modeling is not frequently performed mainly for two reasons: 1) The requirements to capture the behavior of multiple horizontal wells with multiple hydraulic fractures could be computationally prohibitive and 2) The wells in extremely low permeability formations would have minimal interaction. Although the first reason could be a legitimate limitation depending on the objectives of the reservoir project, the second one is arguable. Depending on the spacing and the volume of the fracturing treatments, in many cases, production data collected from shale plays have shown that horizontal wells may interfere with each other during production. Therefore, in projects where the main objective is well spacing or completion optimization (among other important objectives) a comprehensive multi-well reservoir simulation study is required.

This paper discusses several aspects that highly impact the reservoir simulation workflow for LRS plays: Geomodeling (seismic, geology and petrophysics), gridding (tartan grids, Cartesian grids, and unstructured gridding), PVT, flow models (dual/single porosity models), hydraulic fracture modeling, microseismic and SRV estimations, among others. The study suggest that in multi-well reservoir simulation of LRS plays, optimum grid design, proper capture of SRV and natural fractures corridors, and adequate modeling of PVT properties are the most critical factors to accurately optimize wells and completions spacing. Finally, a reservoir simulation workflow is proposed to properly address the critical factors. Field examples from the Eagle Ford and another emerging shale play are presented to support the proposed workflow.
Excitable Nanoparticles for Trapped Oil Mobilization
Authors: Soares Fernando Saint-Martin , Prodanovic Masa , Huh Chun
Published: June 2014

Ferrofluid is a stable dispersion of paramagnetic nanoparticles in a liquid carrier. The easily controllable magnetization of ferrofluids has motivated their use in a broad range of applications, from bioengineering to sealing of bearings. Recently, it was verified that nanoparticles with specifically-designed coating can be injected into reservoirs without significantly compromising permeability and with little retention. This suggests a potential for ferrofluid applications in enhanced oil recovery (EOR). We investigate this potential numerically through a method which, for a given external magnetic field, provides the equilibrium configuration of an oleic phase inside some pore geometry in the presence of dispersed excitable nanoparticles in surrounding brine. We adapted an existing level-set-based method for fluid-fluid displacement to include magnetic forces exerted on the fluid interface. Level set functions can easily accommodate complex shapes by representing the fluid-solid and fluid-fluid interfaces implicitly. The magnetic pressures depend locally on the magnetic field intensity and direction which in turn depend on the fluid configuration. Interfaces represent magnetic permeability discontinuities and hence cause disturbances in the spatial distribution of the field. The magnetic field solver handles these discontinuities through an immersed interface method.

Results indicate that, aside from its straightforward dependency on the ferrofluid susceptibility, magnetic pressures are strongly influenced by the pore geometry. Stresses are amplified near the contacts between a ganglion and the pore wall. The oil ganglia tend to adjust to the stress configuration by detaching from the wall.

The stresses produced by the magnetization of ferrofluids could help to overcome strong capillary pressures and displace oil ganglia. A synergy of existing EOR methods (e.g. surfactant injection) and ferrofluids excited by a magnetic field has a potential to mobilize more trapped oil near wellbore.
Wettability Alteration in High Temperature Carbonate Reservoirs
Authors: Chen Peila , Mohanty Kishore K.
Published: June 2014

The objective of this study is to develop strategies to improve oil recovery in highly fractured carbonate reservoirs at high temperatures (100°C and above). Such reservoirs usually contain high salinity and high hardness formation brines. The use of nonionic surfactants or anionic surfactants (Carboxylates and Sulfonates) to alter oil-wet reservoirs towards more water-wet was investigated under harsh reservoir conditions. A nonionic surfactant Ethomeen® T/25 has shown aqueous stability at high salinity and temperature with high effectiveness in wettability alteration and imbibition oil recovery. Anionic surfactant formulations were developed to recover oil mainly by gravity drainage since they did not show wettability alteration effect in hard brine. Both experimental and simulation studies have shown that sulfonate/carboxylate surfactants achieve high performance in wettability alteration and spontaneous imbibition only when they mix with chelating agents in formulations. Chelating agents, especially EDTA.4Na and sodium polyacrylate (NaPA) have been tested for their compatibility and effectiveness in the surfactant formulations. By sequestering divalent ions in hard brine, chelating agents free anionic surfactants to react at the solid-fluid interface to alter wettability of carbonates from oil-wet towards more water-wet. The chelating agents trigger mineral dissolution, but that does not lead to wettability alteration or contribute to the imbibition oil recovery directly.
Well Placement Optimization Constrained to Minimum Well Spacing
Authors: Awotunde Abeeb A. , Naranjo Carlos
Published: June 2014

Efficient recovery of hydrocarbon resources is one of the challenges facing the oil and gas industry. In an enhanced oil recovery (EOR) scheme, optimal placement of wells plays an important role in determining the amount of oil that can be recovered with the selected EOR process. Once the reservoir flow paths have been established, it necessary to find an optimal configuration of wells that will yield the highest net present value (NPV). Traditionally, well placement optimization (WPO) has been done through experience and use of quality maps. However, in recent times, there has been a gradual shift from traditional methods to automatic well placement that uses gradient-based or stochastic search algorithms to locate the optimal positions of wells. This technology has enabled improvement in the decision making process. Despite the successes achieved, the optimization tools rarely enforce well spacing constraints during the optimization process. This often results in well configurations with high NPV but also with physically unrealistic well positions.

In this paper, we propose to solve the well placement optimization problem constrained to any desired minimum well spacing. Minimum well spacing here refers to the minimum distance between any two wells that a company or an asset team considers technically safe. First, we develop the nonlinear inequality constraints needed to enforce minimum well spacing, then formulate the well placement problem as a constrained optimization problem and subsequently adopt the penalty approach to solve the constrained well placement problem. The covariance-matrix adaptation evolutionary strategy (CMA-ES) was used as the global optimizer in solving the optimization problem.

Two examples were used to show the effectiveness of the approach. Results obtained from this approach were compared with those obtained from the unconstrained WPO. The results show that the method can successfully determine optimal well locations without violating any of the constraints. In contrast, the unconstrained optimization approach failed to satisfy some of the nonlinear constraints and in some cases yielded well configurations in which two or more wells are placed at exactly the same location (on top of each other).
Use of Laboratory Scale Apparatus for Simulation of Downhole Stimulation Monitoring With Distributed Temperature Surveys
Authors: Pinto Hardy , Frederico Eira Carlos , Rosas Fabio , Carneiro Fernando , Bobula Deny
Published: June 2014

Adequate fluid placement and complete zonal coverage during a matrix acid stimulation is critical to the success of a treatment. The use of distributed temperature sensing (DTS) is a relatively new technique that can be used for monitoring downhole fluid placement during a treatment. It uses a fiber-optic distributed-temperature-monitoring system to provide continuous temperature profiles throughout the entire length of the well, giving relevant information to perform qualitative and, in some cases, quantitative analysis of fluid placement downhole.

This paper describes the design and construction of a laboratory scale flow-loop apparatus to demonstrate the application of DTS technology for downhole fluid placement monitoring. The apparatus constructed contains three inlet and exiting points to simulate well perforations, a method to raise or lower fluid temperature and thus introduce temperature spikes or tracers, and optical fiber and sensing equipment and instrumentation to measure and compare measured and calculated rate data. The system is capable of simulating several well flow conditions, such as fluid injection, fluid production and crossflow.

The designed apparatus has proven to be versatile, compact, and useful for understanding and training professionals regarding how DTS technology can be used for monitoring downhole fluid flow and placement.
Completion Influence on Production Decline in the Bakken/Three Forks Play
Authors: Gullickson Geoffrey , Fiscus Kirk , Cook Peter
Published: June 2014

Recent developments in completion techniques and stimulation efficiency have allowed many unconventional resource plays to reach economically viable levels. The Bakken/Three Forks play of the Williston basin has rapidly evolved during recent years, and its predominantly successful completion techniques continue to emerge as programs are tailored to geographic areas. As completion intensity increases to facilitate higher early time production returns, so does the need for the critical analysis of production decline rates to meet economic targets.

The application of decline curve analysis in unconventional reservoirs, such as the Bakken/Three Forks play in North Dakota, is often problematic because of very long periods of transient flow. This has caused the development of various decline curve relations outside the conventional Arp's equations in an attempt to better explain the transient flow period. Additionally, it has sparked interest in quantifying the uncertainty associated with production and the estimated ultimate recovery (EUR) from these various techniques.

The Bakken/Three Forks system is exploited using a large variation of publically reported completion techniques throughout a significant geographic area. Because of the uncertainty in assessing the performance of unconventional wells and the multitude of variables that could affect their production, it is often difficult to determine dominant influencing parameters of completion design. Efficiently implementing optimal completion techniques, provided there is high variability within a continuous horizontal target lithology, is critical because of the large geographic extent of the Williston basin.

The focus of this study is to evaluate the completion efficiency of individual wells using decline curve analysis and to quantify uncertainty using this performance metric. A comprehensive completions database of the Bakken/Three Forks play is used to evaluate the expected costs and benefits of various completion designs used throughout the basin. This paper provides examples of stimulation methods optimized to specific regions of the Bakken/Three Forks system using this methodology.
Use of Conventional Well Logs In Selective Completion Designs for Unconventional Reservoirs
Authors: Barree R. D. , Conway M. W. , Miskimins J. L.
Published: June 2014

A common issue in unconventional reservoir completion and stimulation design is the selection of fracture initiation points to effectively contact producible reserves. One solution is to equally space initiation points along the entire well, with the trend being to closer spacing to increase reservoir contact. A second approach is to use some combination of logs in the lateral to selectively complete sections that appear to have better reservoir quality or producing capacity. In areas where the rock properties are relatively consistent in terms of reservoir quality, the two methods may overlap so that uniformly spaced fractures offer the best opportunity to for effective stimulation. In other cases, where sections of the lateral are out of zone, or in identifiably inferior reservoir quality, portions of the lateral may be skipped to decrease overall completion cost. This paper presents a method to use and integrate multiple well logs in both vertical and horizontal wells to identify hydrocarbon bearing intervals (storage) and highly productive zones (possibly "natural" fracture sets) for selective completion.

Correlations have been found between acoustic velocity, resistivity, gamma-ray, and porosity logs and core-derived properties such as hydrocarbon saturation and TOC%. These correlations have been expanded to include mud log gas shows and ROP (rate of penetration) to differentiate between matrix and secondary fracture contributions to production. With very little core data it is possible to derive a regional model that predicts TOC% from simple log measurements that are commonly available. The analysis strongly suggests areas of a well that should be primary targets for stimulation, zones that can be bypassed with little economic downside, and sections of the well that should not be considered for zonal isolation such as packer setting points. The method has been applied in many unconventional development areas, including the Marcellus, Utica/Point Pleasant, Wolfcamp/Avalon, Duvernay, Montney, and Eagle Ford with equal success. Results have been confirmed by post-frac production logs in cases where complete data sets are available.
Microemulsion vs. Surfactant Assisted Gas Recovery in Low Permeability Formations with Water Blockage
Authors: Rostami A. , Nasr-El-Din H. A.
Published: June 2014

Despite all advantages of slickwater fracturing such as low cost, high possibility of creating complex fracture networks, and ease of clean-up, large quantities of water are still left within the reservoir after flowback. Invasion of aqueous fracturing fluids can reduce the relative permeability to gas and thereby cause a water blockage.

Compared to conventional surfactants that lose their activity after contacting just first few inches of formation due to quick adsorption to the rock surface and limited thermal stability, microemulsions with smaller droplet sizes and lower surface tension can penetrate deeper to the formation and will result in significant gas recovery from low permeability formations. Micro-emulsions have shown to be an effective remedy for improving gas relative permeability due to their structure which can pro-vide maximum surface area of contact between surfactant and formation.

Experiments were conducted using outcrop of Bandera sandstone cores to measure the effect of liquid blocking on gas relative permeability. Microemulsion treatment was developed to reduce the damage caused by water and condensate blocking. The chemical treatment alters the wettability of water-wet rocks to less water-wet and increase the gas relative permeability.

The increase in gas relative permeability was quantified by comparing the gas relative permeability before and after treatment. The alteration of wettability after the chemical treatment was evaluated by measuring the contact angles between the solution and rock. Thermal stability tests were conducted using hot rolling cells for temperatures up to 400°F which proved the high stability of microemulsion solutions at HP/HT conditions. Microemulsion solutions showed very good results in gas permea-bility regain, when compared to the other treatment solutions. They can provide excellent fluid cleanup by flowing out of the well to the surface where the entrapped water can be recovered.