bluuebunny/crossref_metadata_2025 huggingface dataset:
The Cottonwood Field Case History: The Pig/Paraffin Obstruction of a Long Subsea, Deepwater Tie-back and Its Successful Remediation
Authors: Shecaira Farid , Barros Dalmo , Ramachandran Kartik , Bonin George , Waltrich Paulo , Jennings David , Newberry Mike , Ziglio Claudio
Published: October 2011

Cottonwood is the first field development in deepwater Gulf of Mexico operated by Petrobras. It consists of three subsea wells in water depths of 670m (2,200 ft). Two wells presently produce gas-condensate, with high wax deposition potential. The wells are connected to a fixed platform in East Cameron 373 Block, 27.2 km (17 miles) away, through a piggable loop with flowlines of 15.2 cm (6") nominal and 12.2 cm (4.8") ID. During a pigging procedure in December 2007, a rigid, 12.9 cm (5.1") elastomer pig got trapped halfway in the East segment of the loop, after traveling through the West segment. In front of the pig a slug of paraffin was formed and impeded its passage.

During two years the production continued through the still open West segment of the production flowline. A wax mitigation plan was implemented, consisting of continuous paraffin dispersant injection. Meanwhile, low-cost, advanced technology-based methods to remove the obstruction were pursued, as an alternative to the high-cost whole or partial East flowline substitution. The procedures attempted were, first, the controlled pressurization of the flowline, second, the application of associated vibration and pressurization. These methods, along with paraffin solvent soaking procedures, helped to release the pig in February 2010, making both segments available for production. However, a layer of wax was formed inside the flowline loop and pig fragments might still be present in the East segment.

A cleaning operation was performed to further clean both flowline segments. The operation consisted of injecting sea water mixed with a dispersant, an approach, to our best knowledge, not attempted before in such a long subsea tie-back. The formulations used were thoroughly laboratory tested. The operation demanded noticeable logistics planning and execution, due to the flowline volume (4000 bbl) and the number of volumes circulated (circa of 10). The operation was a success, thereby allowing the restoration of production with full flowline diameter availability and the resumption of routine pigging of the loop.
Liner Drilling Technology as a Tool to Reduce NPT - Gulf of Mexico Experiences
Authors: Rosenberg Steven M. , Gala Deepak M.
Published: October 2011

It is increasingly difficult to find hydrocarbon reserves located in benign environments, a situation which has resulted in the oil and gas industry moving to locations where significant drilling challenges are encountered. These challenges often lead to costly nonproductive time (NPT) and increased operational risk. To reach their objectives, operators must make decisions "outside the box" to mitigate these risks. Liner drilling (LD) technology has been introduced in recent years as a well construction technique and has proved to significantly reduce NPT and operational risks. As seen in some of the case histories, LD in lieu of conventional drilling methods was identified as the only practical way for the operator to accomplish his objective(s)—well abandonment being the only other alternative.

This paper presents five case histories, in both shelf and deepwater Gulf of Mexico (GOM), where LD technology was applied to mitigate lost circulation, wellbore stability issues, and other drilling hazards. Also included is a discussion of the liner tool and casing bit systems that were implemented as well as brief well histories depicting the drilling hazards mitigated and the eventual outcomes. The operational parameters are highlighted together with the LD results and the associated value to the operator.
Casing and Screen Failure Analysis in Highly Compacting Sandstone Fields
Authors: Furui K. , Fuh G.-F. , Morita N.
Published: October 2011

Many casing and screen damage incidents have been reported in deep-water oil and gas fields in the Gulf of Mexico and other locations around the world. We reviewed historical casing/well failure events in a highly compacting sandstone field and performed a comprehensive geomechanics analysis of various casing damage mechanisms (tension, axial compression, shear, and bending) related to large reservoir depletion. Among five wells that experienced mechanical well integrity issues, two of them showed casing restrictions in the cap rock at intervals around 1,000 to 1,600 ft-TVD above the top of the depleting (main) reservoir. A multi-finger caliper log obtained from one of the wells indicates that the overburden casing failure occurred at a highly geo-pressured, thin sand layer approximately 1,100 ft-TVD above the top of the compacting reservoir. The remaining casing failure events occurred near (less than 200 ft-TVD) or within the compacting reservoir interval.

A 3D non-linear finite element model has been developed for simulating stress changes in the overburden and the reservoir intervals and evaluating the effect of lithological anomalies on casing stability. The simulation results indicate that large tensile and shear strains could develop within a thin, weak-strength layer in the overburden and at the interface between cap rock and depleting reservoir interval. Casing damage by bending/shear could also occur at these thin-layered sands saturated with overpressured gas.

In the reservoir interval, shear stresses acting on the screens can be relatively high due to the difference of the movements between the internal base pipe and the external shroud and gravel. Screen failure may also occur at the welded points. If casing failure occurs in the unperforated sand layer just above the compacting reservoir, it induces localized high velocity flow on the upper part of the screen causing potential screen erosion. Casing failure due to fault slip near the reservoir occurs only if a fault has sealing capability while maintaining a large pressure differential across the fault plane.

The numerical analysis results presented in this work help engineers understand possible casing and screen deformation and failure mechanisms experienced in highly compacting sandstone fields. Based on the study findings, we also present completion design guidelines to avoid or mitigate compaction-induced casing damage in both the overburden and reservoir intervals.
Subsea Well Fluid Intervention Using MARS (Multiple Application Reinjection System)
Authors: Petrone Daniele
Published: October 2011

Subsea Well Interventions offer many challenges. The population of subsea wells is now in the region of 4000 and is anticipated to continue to grow, with expansion into deeper waters and more hostile environments. Historically, the cost of intervention on subsea wells has negatively influenced its uptake; however, this is changing with advancing technologies, as operators seek to improve recovery from their subsea assets. Fluid intervention does not require vertical well access for wireline or coiled tubing services: it involves pumping chemicals into the well in a controlled, safe manner. There are a number of fluid intervention applications, examples of which are: to protect the well against scale and hydrates; pumping of kill weight brine for the purposes of well control; cleaning the lower completion or stimulating the reservoir to tackle formation / production issues that can evolve throughout the life of the well. In 2008, an operator in the North Sea utilised the first MARS based subsea well intervention system, to carry out scale squeeze operations in the on a North Sea field from a DSV. Further successful campaigns have been completed in 2009 and 2010 in addition to a 10,000 psi system being ordered for other fields. By adopting a standardised method for scale squeeze operations, Shell has been able to reduce the cost and maximise the efficiency of their operations. Subsequently an operator in Angola has adopted the same philosophy for their subsea field while considering additional MARS options for well sampling and metering; successful operations where performed in 2009 and 2010 and 2011, allowing continuous production while reducing the cost of intervention. A major project in the Gulf of Mexico has been sanctioned where the technology will be used also. This paper will describe the operational and cost benefits of utilising MARS for subsea well intervention and update on the operational performance of this methodology as it matures.
Changing Roles, and Optimizing Well Construction Performance in Russia
Authors: McMorran Paul , Lopez Jorge
Published: October 2011

From 1998 to 2010, after years of decline, Russia's oil production increased by 66% from 6.2 million bbl/day to a post-Soviet record of 10.3 million bbl/day1. Significantly, this period also witnessed the creation of an independent oilfield services (OFS) sector as Russian operators adopted global practice and began to outsource non-core activities.

Following decades of in-house drilling and related operations by State enterprises, the emergence of independent contractors, as well as market-driven operators, have created the conditions to transform well construction performance. Integrated service providers take this a step further by optimizing the process from well design through construction to completion.

This paper outlines how, in less than a decade, Russia's oilfield service sector is transforming field development economics. It focuses on the technologies, processes and motivational issues that drive performance in well construction, based on international practice but adapted to Russia's uniquely challenging environment.

The paper describes operational, financial and HSE-related improvements that independent contractors deliver at each step of the well construction process. It identifies opportunities for further gain through integrated project management, provided supporting processes and infrastructure are in place.

Russia remains a frontier for our industry and for the SPE. This paper offers an understanding of the rapidly-changing roles of professionals and rig crew at engineering centers and well sites across the country, and how these impact well construction performance. It points to trends that operators, contractors and others can expect to encounter as Russia's oilfield transformation continues.
Practical Assisted History Matching and Probabilistic Forecasting Procedure: A West Africa Case Study
Authors: Dujardin B. O. , Matringe S. F , Collins J.
Published: October 2011

To improve the reliability of reservoir performance predictions, subsurface uncertainties must be accounted for in production forecasts. Probabilistic methods are commonly used to understand and quantify the impact of uncertainties on reservoir behavior. This paper presents a structured and practical probabilistic history-matching and production forecasting workflow that was successfully applied to 6 reservoirs in a West-Africa field with several years of production history and a challenging data monitoring environment. The workflow was found to be very efficient as the 6 reservoir models were constructed, history-matched and run in predictions in less than three months. A recent look-back on the probabilistic predictions with a year of new production data proved the robustness of the workflow.

The procedure used in this paper starts with a thorough review of subsurface uncertainties. All available static and dynamic data is analyzed to define uncertainty parameters and corresponding ranges. Next, a first set of simulations is performed, with each uncertainty parameter varied independently in order to analyze its effect on history-matched quality and future reservoir performance. The parameters with little impact are screened out during this step. The key parameters retained are then used to define a new set of simulations through experimental design. The models are run and the results are used to generate response surfaces for each history-match parameter and reservoir performance metric. Using a Monte-Carlo sampling procedure, thousands of uncertainty parameter combinations are tested using the response surfaces and screened using tolerances on various history-match parameters. This approach avoids the cumbersome and subjective definition of an objective function and allows the selection of a large number of parameter combinations that yield a history-match. Several models were selected to represent the 10th, 50th and 90th percentile of original oil in place and reservoir ultimate oil recovery. These probabilistic models are then run into prediction under different development scenarios, allowing for optimization of well locations and field operational constraints.
Automated Alarms for Managing Drilling Pressure and Maintaining Wellbore Stability—New Concepts in While-Drilling Decision Making
Authors: Sadlier Andreas , Wolfe Chris , Reese Mike , Says Ian
Published: October 2011

Due to the increased complexity of oil and gas wells being drilled worldwide, many encounter significant geologic uncertainty during wellbore construction. This uncertainty can be manifested in the form of unplanned drilling events such as kicks, lost circulation, and borehole stability problems. These issues expose operators to serious health, safety and environmental (HSE) risks and frequently lead to significant cost overruns. However, if a more proactive effort was placed on predicting and identifying trouble zones in real time, it may be possible to achieve a substantial reduction in nonproductive time (NPT) while simultaneously reducing safety risks.

With the abundance of drilling and logging data now available in real time, much of this information can be used to recognize potential problem areas while drilling. Until recently, ensuring that the right person receives the right information at the right time to make an informed decision has been accomplished primarily through manual processes. However, computer systems available today can automate the filtering and distribution of relevant information to personnel quickly for more rapid assessment of the current situation.

In addition to data handling and distribution, these systems can also provide automated alarms that aid in reducing the probability of an unplanned event by focusing the attention of personnel on the most important datasets as well as their interpreted relationships. Alarms can automatically interpret complex real-time datasets in the context of pre-well models and quickly provide warnings without relying solely on the experience of the individual to decipher the information in context and detect potential danger. They also provide assistance for less experienced personnel enabling better risk assessment awareness and, in turn, more reliable decision making.

This paper presents a case study for a system of real-time automated wellbore stability alarms aimed at identifying trouble zones and improving ahead of the bit predictions. The goal was to reduce the potential for kicks, lost circulation and wellbore instability events. Special software is used for processing real-time data, in the context of geomechanical modeling, and raising appropriate alarms when conditions cause drilling parameters to deviate outside an acceptable level. The case study also discusses how these alarms can be used in a remote services platform by transmitting real-time information from the wellsite to experts in town, which enhances collaboration and improves customer value through better engagement. Finally, the paper describes how automated alarms help to establish and enforce better communication protocols and accountability through an acknowledgment process that includes depth and time-based comments.
Impact of Water Hammer in Deep Sea Water Injection Wells
Authors: Choi Suk Kyoon , Huang Wann-Sheng (Bill)
Published: October 2011

Water hammer is a known pressure pulse or surge that may occur by the instant shut-in of a valve in a flow line. Sudden momentum change may create a pressure cyclic pulse that could cause damage to valves, bending parts in tubing, and/or joints. Usually this effect has been well managed in surface facility design; however, it tends to be overlooked in subsurface well design. Additional possible impact by water hammer in subsurface wells could be on the sandface completions. The severe water hammer could cause failure of formation integrity, resulting in sand production. It may also damage the wellbore and downhole completions. Especially for deep sea water injection and/or production operations, water hammer effect needs to be thoroughly investigated and properly managed because it could be more severe due to longer flow line and higher flow rate.

The purpose of this study is to have a comprehensive investigation on water hammer effect for an actual water injection well in Chevron's deep water project with different design parameters and operating parameters. The design parameters include a) height of vertical riser; b) tubing diameter; c) injectivity index (skin or completion type); d) sandface wellbore length; and e) well deviation. The operational parameters include a) injection rate; b) closing time; and c) injection water temperature. Multiphase transient fluid flow model OLGA is used for the water hammer simulation.

Results of the water hammer parameter study for optimum well design and operating strategy are reported here. It is shown that the impact of water hammer can be significantly mitigated or eliminated at well design stage or by adjusting the operating parameter(s).
A New Approach to Modeling Fracture Growth in Unconsolidated Sands
Authors: Agarwal Karn , Sharma Mukul M.
Published: October 2011

Fracture growth in soft rocks and unconsolidated sands is currently modeled assuming linear elastic, brittle behavior. Observations from past experimental work show that fracture propagation in unconsolidated sands is a strong function of fluid rheology and leak off and is accompanied by large inelastic deformation and shear failure leading to high net fracturing pressures. This paper presents a new approach to modeling fracture propagation in unconsolidated sands.

It is shown that the classical approach to fracture modeling that uses the stress intensity factor at the fracture tip is not suitable for unconsolidated sands. The fracture propagation criterion in our model is not based on the conventional stress intensity factor approach. Both shear and tensile failure are modeled, and both play an important role in controlling the fracture growth. Fluid loss is modeled accurately using a filtration model that accounts for a reduction in porosity and permeability induced by particles in the injected fluids as well as the possibility of filter cake formation.

The model predicts considerably higher net fracturing pressures due to plastic yielding in shear around the fracture. In general there is a zone of shear failure ahead of the tip which subsequently fails in tensile mode at higher net fracturing pressures resulting in fracture propagation. Shear failure is observed to be the dominant failure mechanism in case of low efficiency fluids, with very little fracture growth in tensile mode. However, tensile fractures of considerable length surrounded by a zone of shear failure are obtained in the case of high efficiency fluids or in the case of fracture face plugging by particles present in the injected fluid. The model thus clearly shows for the first time that fractures in sands can behave quite differently under different conditions. The results of the sensitivity study conducted on the important parameters are consistent with the observations reported in experiments.

The model significantly improves our understanding of the effect of key parameters such as the injection rate, fracturing fluid properties and mechanical properties of the sand on the fracturing process. It is expected that the model will find application in designing frac-pack treatments and solid waste disposal in unconsolidated formations.
First Borehole to Surface Electromagnetic Survey in KSA: Reservoir Mapping and Monitoring at a New Scale
Authors: Marsala Alberto F. , Al-Buali Muhammad , Ali Zaki , Ma Shouxiang Mark , He Zhanxiang , Biyan Tang , Zhao Guo , He Tiezhi
Published: October 2011

The first Borehole to Surface Electromagnetic (BSEM) pilot field survey in the Kingdom of Saudi Arabia (KSA) was successfully executed to identify oil and water bearing reservoir layers in a carbonate oilfield water injection zone.

Maximizing recovery factor by means of detailed mapping of hydrocarbon accumulations in the reservoirs is a key requirement for oil producing companies. This mapping is done routinely by accurate measurements of fluid distribution at the wells’ locations, but a knowledge gap exists in the inter-well volumes, where typically only density-based measurements are available (seismic and gravity). Such technologies are not always effective to discriminate and quantify the fluids in the porous space (especially when difference in fluid densities is small, such as oil and water). On the contrary, when high electrical resistivity contrasts exist between hydrocarbons and water, electromagnetic (EM) based technologies have the potential to map the distribution of the fluids and monitor their movement during the life of the field, hundreds of meters or kilometers away from the wellbores.

The objective of a BSEM survey is to obtain fluid sensitive resistivity and induced polarization maps. These are based on an acquisition grid at the surface, a few kilometers around the EM transmitting well, which reveal oil and water bearing zones in the investigated reservoir layers.

In this pilot field test, BSEM showed the potential to map water-front movements in an area of about 4km from the single well surveyed, evaluate the sweep efficiency, identify bypassed/ lagged oil zones, and eventually monitor the fluid displacements, if surveys are repeated over time. The data quality of the recorded signals is highly satisfactory. Fluid distribution maps obtained with BSEM are coherent with production data measured at the wells’ locations, filling the knowledge gap of the interwells area.

Three key R&D objectives for this BSEM pilot are achieved. Firstly, the capability to record at the surface EM signals generated in the reservoir, secondly, the capability of BSEM to discriminate between oil and water saturated reservoir zones, and finally obtain resistivity maps and a fluid distribution estimate plausible and coherent with the information obtained from well logs, crosswell EM, production data and reservoir models.

In addition to reservoir monitoring, BSEM can be very useful in non-diagnosed areas like exploration fields for hydrocarbon exploitations.
First Installation of Alternate Path Openhole Packer Providing True Zonal Isolation in Openhole Gravel Packs
Authors: Hecker Michael T. , Barry Mike D. , Ryan James T. , Ruiz Vicente F. , Stevens Peter , Pedro Nanga , Yeh Charles S. , Inglesfield James
Published: October 2011

Openhole completions are often selected as the preferred completion technique to provide high capacity, low skin completions. With the advances of Alternate Path® Technology (APT), a full gravel pack can be realized under challenging well conditions to provide increased long-term reliability. One draw back to openhole gravel packs (OHGP) has always been the inability to isolate undesirable water or gas, whether it be during the initial completion or during the production lifecycle of the well. Numerous improvements have been made in recent years with openhole packers to provide zonal isolation in standalone screen applications. Unfortunately, not all formations can be successfully completed with standalone screens due to non-uniform sand grain sizes, high concentration of mobile fines, or low hole angle through the pay interval. To achieve the benefits of zonal isolation, operators have opted to either complete the well as a cased hole completion, extend the limits of standalone screens beyond generally accepted best practice guidelines, use expandable screens with isolation, or attempt to seal the openhole annulus with swellable materials after gravel packing. These options may not be optimal and can compromise the ultimate recovery potential of the well.

A new openhole packer with APT, Shunt Zonal Isolation (SZI) packer, has been developed and successfully deployed. When run in conjunction with Internal Shunt Alternate Path Technology (ISAPT) screens, true zonal isolation in openhole gravel pack completions can be achieved. This packer can be run through 9⅝-in. casing, is set before gravel packing begins and forms a seal against the borehole to provide true annular isolation in either round or oval hole sizes up to 10 ¾-in. The openhole annulus above the packer is gravel packed conventionally, then slurry is diverted through the shunt system to gravel pack below the isolation packer. Alternate Path Technology ensures the annular space, both above and below the isolation packer, is completely packed.
A Capacitance-Resistive Model and InSAR Imagery of Surface Subsidence Explain Performance of a Waterflood Project at Lost Hills
Authors: Wang Wenli , Patzek Tad W. , Lake Larry W.
Published: October 2011

Extraction of oil and gas can cause reduction in pore pressure, occasionally resulting - in shallow reservoirs - in subsequent compaction that forms a surface subsidence bowl. In the last 10 years, there has been over 10 feet of subsidence in parts of the Lost Hills diatomite oil field in California (Bruno et al.1992). The surface subsidence at Lost Hills not only causes damage to surface facilities and wells, but also reactivates faults and reduces rock permeability. Subsidence makes reservoir optimization difficult. Hence, it is important to assess or predict the surface subsidence and the reasons for subsidence early in the life of an oil field to make an optimization plan.

We use jointly the capacitance-resistive model (CRM) (Alberoni et al. 2003 and Yousef, et al. 2006) that relies only on injection and production data, and the inSAR satellite imagery of surface subsidence. From CRM simulations, we estimate the connectivity between injectors and producers as well as general water flow directions from individual injectors. We then superimpose well connectivity and inSAR imagery to diagnose the reasons for the subsidence. Using a new surface subsidence model, which is based on the continuity equation of CRM and rock mechanics, we are able to predict the average surface subsidence at Lost Hills from the injection and production rates.

Our work shows that there was significant volumetric rock damage at Lost Hills and the well connectivity changed dramatically with time because of the water injection- and compaction-caused rock damage. We conclude that for a soft, fragile and nearly- impermeable rock such as the diatomite, high injection rate weakens the rock and creates dynamic water flow tubes or ‘channels’ without providing good pressure support to the reservoir. These high permeability ‘channels’ recirculate most of the injected water between the injectors and producers.

Our CRM/inSAR approach is new and gives insights into the time-dependent and spatially variable fluid flow fields in a relatively shallow waterflood. Consequently, we may be able to suggest optimum water injection strategies to enhance oil production, while minimizing rock damage and surface subsidence. In addition, the proposed surface subsidence model is a convenient and reliable way to predict the average subsidence.
Numerical Indicator for Flow Through Heterogeneous Permeable Media
Authors: Ghanbarnezhad Rouzbeh
Published: October 2011

This paper suggests a numerical indicator to examine the nature of miscible displacements in heterogeneous permeable media. We compare miscible displacements through assigning a numerical value to the governing flow regime. Previous studies point out that the competition between effects is the cause of developing various types of flow regimes (dispersive, fingering, gravity override, and channeling). However, the distinction between the flow patterns is only possible qualitatively (visually) so far; therefore, the visual traditional method fails to properly characterize displacements with a similar flow pattern and lacks the capability of evaluating the displacement performance as the flow regime changes.

We adopt the notion of the correlation coefficient function and use the progression of the mixing zone to assign the numerical values to the flow regimes. The correlation coefficient function of the lengths of the mixing zone calculated between two different times represents the tendency to propagate linearly with time. On the other hand, the correlation coefficient function of the squared length of the mixing zone corresponds to linear growth with Time. Using the arithmetic average of the correlation coefficient functions over successive time intervals, we introduce a flow regime indicator to study the nature of miscible floods. We use a simulation approach to validate the numerical indicator. The numerical values assigned to the flow patterns are consistent with the visual identification of flow patterns.

We conclude that the pattern attributed value is an effective measure of the mixing zone development in heterogeneous permeable media for the the limited cross flow. The suggested procedure identifies the type of flow regime at any stage of displacement and helps monitor evolution of the mixing zone. The latter is important in prediction of displacement performance. Through this study, we investigate the relation between the attributed numerical values and the displacement performance.
Modeling Surfactant Enhanced Oil Recovery From Short And Long Fractured Carbonate Cores And Scaling Of Results To Field Applications
Authors: Alamdari Baharak B. , Kazemi Hossein , Salehi Mehdi , Thomas Charles , Izadi Mehdi , Manrique Eduardo
Published: October 2011

This paper presents the results of oil recovery from short fractured and unfractured carbonate cores using a high speed centrifuge. Also, we will provide results of oil recovery in long cores. The short cores are 1.5-inch long while the long cores are 12-inch long. The experiments are designed to decipher contributions from rock matrix in presence and absence of fractures, and for imbibition and gravity drainage oil recovery with and without surfactant. The laboratory results are scaled to field using scaling rules as well as numerical simulation.

The purpose of this research is to demonstrate that surfactant oil recovery can be a viable enhanced oil recovery process in fractured carbonate reservoirs when fracture distribution and connectivity are favorable. Furthermore, these carefully designed experiments improve our understanding of how oil mobilization can be enhanced in fractured carbonate rocks and how the process can be modeled and solved numerically.

The cores were selected from a carbonate outcrop, saturated with brine, displaced with a 22-centipoise crude oil from a specific field, and were aged to promote oil-wetness. A typical unfractured long core had a spontaneous imbibition oil recovery of zero, but produced 2% oil in a 5000 ppm anionic surfactant solution. The long fractured cores had a spontaneous imbibition oil recovery of 21% and a surfactant oil recovery of 38%. The short cores in the centrifuge produced substantially more oil because of enhanced gravity effects. The implication of these results to field applications, and much more, will be discussed in the paper.

We were able to match experimental results using an in-house numerical model, where, we believe, the model's theoretical basis is consistent with the physical principles of fluid flow in porous media. The results of these experiments, and our experience in a major fractured carbonate reservoir, have given us a better understanding of the mechanism of enhanced oil production in fractured carbonate reservoirs by dilute surfactant solution and micellar solutions. We are hoping that the results of this research will promote field applications.
Optimizing Transverse Fractures in Liquid-Rich Formations
Authors: Vincent M. C.
Published: October 2011

Horizontal wells provide the opportunity to initiate multiple transverse fractures and dramatically increase the connection between the wellbore and the hydrocarbon-bearing reservoir. This has allowed the economic development of low permeability reservoirs that cannot be pursued without reservoir stimulation. Our success, however, does not imply that we are optimized.

Recent field results in the Niobrara, Bakken, Viking, Haynesville, Eagle Ford and other reservoirs completed with transverse fractures are yielding answers to many questions, including:

Are we achieving acceptable vertical height growth? What adjustments are necessary to accommodate multiphase flow? What fracture conductivity is needed? How many frac stages will provide the optimal economic returns? Are we effectively stimulating each stage? Are precautions necessary to avoid or reduce overflushing of proppant? Will restimulation of these reservoirs be necessary given current completion strategies?

This paper explains the challenges of accommodating multiphase flow in transverse fractures and summarizes theoretical, laboratory, and field results demonstrating the best practices. Evidence is reviewed indicating that fractures fail to sustain hydraulic continuity through many laminations and techniques are suggested that can improve the ability to drain multiple stacked pay intervals with horizontal wells. Updated production results from the Bakken and Eagle Ford should be of benefit to any operator stimulating horizontal wells that produce significant oil, water, or condensate volumes.
Why Y?
Authors: Williams John M.
Published: October 2011

This paper provides an analysis of a widely-used pressure-volume-temperature (PVT) parameter, demonstrating common errors made in its use and the lack of detailed descriptions in common reservoir engineering texts. Use of the Y-function is a valuable tool for increasing the accuracy of bubble point measurements, and it has other important uses, but its detailed application is poorly understood, leading to unnecessary errors in one of the most fundamental PVT properties.

Best practices have been developed and are presented, to encourage proper application of the Y-function, together with detailed recommendations for setting up Excel spreadsheets to help identify the most precise bubble point, and optimize Y-function values.

More extensive use of the Y-function to obtain bubble points for down hole or surface oil samples is recommended as it could improve quality control and selection of more representative samples.
Scale Inhibitor Squeeze Treatments Selection, Deployment and Monitoring in a Deepwater Gulf of Mexico Oilfield
Authors: Jordan M. M. , Kramer Ted , Barbin David , Linares-Samaniego Sandra , Arnette Walter
Published: October 2011

This paper describes field experience and lessons learned from scale-control operations in a deepwater development in the Gulf of Mexico.

The injection of seawater for reservoir pressure maintenance resulted is a high barium-sulfate scaling tendency upon breakthrough of injection water which meant that it was critical to have effective scale management achieve high hydrocarbon recovery for this field.

Use of conventional, water-based squeezes in the field did not deliver the squeeze lifetime expected and for some treatments resulted in production impairment. Hence, based upon risk mitigation, an alternative scale squeeze program was required this alternative program was supported by an extensive set of laboratory tests including reservoir condition coreflooding, based on these laboratory results it was decided to apply squeeze treatments of aqueous scale inhibitor proceeded by mutual solvent to reduce the risk of relative permeability damage and increase squeeze life by enhancing inhibitor adsorption.

Aspects of well cleaning prior to scale squeeze deployment will be outlined as this has proved critical to the success of scale squeeze treatments in these wells which have an asphaltene tendency.

Results from two of the five current scale squeeze treatments are presented to demonstrate that an integrated evaluation, treatment program design using squeeze design software, implementation and monitor (critical ions, inhibitor residuals, suspended solids) approach can being significant benefit to this challenging aspect of flow assurance.

The paper will explore in detail the issues associated with inhibitor-squeeze treatment selection, deployment, monitoring in deepwater Gulf of Mexico and is a good example of implementation of best-practice sharing from another oil basin (Angola, West Africa) were the same operator overcome similar issues.
Innovative Method of Gas Shale Well Intervention with Coiled Tubing/Jointed Tubing Hybrid String
Authors: McNeil Fraser , Ehtesham Asif , Gracey Paul
Published: October 2011

As the industry strives to maximize production in US shale plays, the number of extended-reach horizontal wells being drilled continues to increase in efforts to optimize reservoir contact and increase fracture intensity. Because operators demand the same level of performance achieved on shallower wells while providing a cost-effective and safe solution, these wells present complex challenges for completion and intervention operations.

Coiled tubing (CT) enables an efficient means to deploy tools and perform pumping operations, such as drilling out plugs, wellbore solids cleanout, and matrix or fracture stimulation in a continuous manner. In any well-intervention operation, the CT size is maximized to achieve the desired level of operational efficiency and effectiveness. To reach the target depth of these extended-reach wells, smaller CT must be used because reel capacity is limited. This not only limits the pump rate that can be achieved, but smaller CT is more susceptible to helical lockup and could require costly assistance to achieve depth. Also, many roadway authorities have established size and weight restrictions that can dictate the size of CT used.

A new hybrid solution is now being used to combine the benefits of both CT and jointed tubing (JT) in a single work string. The solution presents many cost benefits while extending the depth of reach that can be accomplished to perform continuous-pumping operations using the optimum diameter tubing and pipe. The system incorporates unique well-control tools that enable seamless functioning of the string in a live well, thus providing considerable time and cost savings.

This paper presents the benefits of the hybrid unit and discusses the enabling technology while providing an overview of field trials of multizone stimulation treatments in the Bakken and Marcellus reservoirs.
A Comparison of Stochastic Data-Integration Algorithms for the Joint History Matching of Production and Time-Lapse Seismic Data
Authors: Jin Long , Alpak Faruk O. , Hoek Paul van , Pirmez Carlos , Fehintola Tope , Tendo Fidelis , Olaniyan Elozino
Published: October 2011

Quantitative integration of spatial and temporal information provided by time-lapse (4D) seismic surveys to dynamic reservoir models calls for efficient and effective data-integration algorithms. We carry out a comprehensive comparison of stochastic optimization methods using both a synthetic and a field case.

Our first case is a challenging synthetic test problem known as the Imperial College Fault Model (ICFM). Three methods, namely, Very Fast Simulated Annealing (VFSA), Particle Swarm Optimization (PSO), and Neighborhood algorithm (NA) are compared in terms of convergence characteristics, data-match quality, and posterior model parameter distributions. Based on the knowledge developed on the ICFM problem, we isolate VFSA and PSO and further evaluate their performance on a field case involving an offshore West African deepwater turbidite reservoir undergoing waterflooding. The field case has a reasonably long production history and good-quality 3D and 4D seismic data allowing the construction of a geologically-consistent model via dynamic calibration. As such, it constitutes a relevant field test for joint seismic-production history matching. We assess the data-match characteristics and the quality of dynamic forecasts delivered by VFSA and PSO in the field case.

Practical guidelines are developed over the course of the studies for selecting a "fit-for-purpose" optimal method for joint history-matching workflows. Our results show that PSO, a population-based method, incurs relatively more computational expenses at a given iteration, but exhibits good convergence characteristics and provides multiple history matched models. The PSO method has emerged more effective compared to the NA and VFSA methods in the ICFM problem. It was also quite effective on the field application. On the other hand, the VFSA method requires comparatively more iterations to converge due to its sequential nature, but it has advantageous features when moderate computing resources are available.
Production and Rock Stability around a Frac-packed Gulf of Mexico Well
Authors: Han Gang , Revay Joe , Kalfayan Leonard , Perez Jorge , Walters Dale , Bachman Robert
Published: October 2011

Frac-packing has been widely used as an efficient sand control method in Gulf of Mexico fields. For frac-packed wells, rock stability issues within the reservoir are not normally considered when well drawdown levels are established. Instead the emphasis is on how the completion's integrity can be maintained given that mobile sand is produced. A frac pack can prevent sand from entering the wellbore; however, a skin increase and PI degradation occurring during production is not unusual. Conventionally, PI decline is believed to result from flow-related fines migration or from mechanical failure of completion equipment.

This paper presents a case in which theoretical quantification of sand failure around a frac pack provides a viable explanation of field observations. In addition to the skin at the fracture face, PI analysis indicates that additional damage, which contributes to gradually increasing PI degradation, has developed around the fracture. Extensive laboratory core testing has shown that fines are produced only moderately even at high fluid flow rates. However, significant permeability reduction occurs when loading stress increases to a threshold level. A near-wellbore geomechanical model with an embedded fracture has been coupled with a flow model to simulate drawdown and depletion effects on rock stability around the fracture.

The placement of a hydraulic fracture during frac-pack operations has been found to have two major effects upon the surrounding reservoir rock. Rock strength is increased at most locations around the fracture, a finding consistent with current industry perceptions. Secondly, certain regions in the vicinity of the fracture tip are weakened as stresses are elevated. Rock starts to fail at a certain level of depletion in either shear or compaction modes, depending upon the rock's location relative to the fracture and its strength and stress path. These findings demonstrate that rock stability needs to be considered when determining drawdown limitations in sand control completions, in order to avoid unexpected PI degradation.
Multi-scale Gas Transport in Shales with Local Kerogen Heterogeneities
Authors: Akkutlu I. Yucel , Fathi Ebrahim
Published: October 2011

Based on micro and meso-scale investigations, a new mathematical formulation is introduced in detail to investigate multiscale gas transport phenomena in organic-rich shale core plugs. The formulation includes dual porosity continua, where shale permeability is associated with inorganic matrix having relatively large irregularly-shaped pores and fractures, whereas molecular phenomena (diffusion and nonlinear sorption) are with the kerogen pores. Kerogen is considered as a nanoporous organic material finely-dispersed within the inorganic matrix. The formulation is used to model and history-match gas permeation measurements in the laboratory using shale core plugs. The results indicate significance of molecular transport and strong transient effects due to gas/solid interactions within the kerogen. In the second part of the paper, we present a novel multi-scale perturbation approach to quantify the overall impact of local porosity fluctuations associated with a spatially nonuniform kerogen distribution on the adsorption and transport in shale gas reservoirs. Adopting weak-noise and mean-field approximation, the approach applies a stochastic upscaling technique to the mathematical formulation developed earlier for the laboratory. It allows us to investigate local kerogen heterogeneity effects in spectral (Fourier-Laplace) domain and to obtain an upscaled "macroscopic" model, which consists of the local heterogeneity effects in real time-space domain. The new upscaled formulation is compared with the previous homogeneous case numerically using finite-difference approximations to initial/boundary value problems simulating the matrix gas release. We show that macro-transport and macro-kinetics effects of kerogen heterogeneity are nontrivial and impact cumulative gas recovery. The work is important and timely for development of new-generation shale gas reservoir flow simulators and it can be used in the laboratory for organic-rich gas shale characterization.
Using Industrial Remotely Operated Vehicles in Stand-by Time for Deep-water Biodiversity Assessment: A Case Study From Offshore Nigeria
Authors: Jones Daniel , Mrabure Charles , Gates Andrew
Published: October 2011

Description

There is very limited information available on the deep water biodiversity offshore Nigeria. Detailed information on seabed communities is vital for effective environmental management of offshore drilling disturbance but collection of environmental data usually require a dedicated research vessel and associated high costs. We present an approach to environmental survey that uses remotely operated vehicles (ROVs), already in place on survey/supply boats, during stand-by time in drilling operations for low-cost and high-quality operations.

Application

Spatially-referenced ROV video surveys were performed following a stratified random design. These, combined with targeted ROV sample collections (of biological specimens, sediment and rock), enabled an accurate quantitative census of biological patterns. Oceanographic data were collected with self-contained data-logging conductivity, temperature and depth sensors attached to the ROV.

Results, Observations, and Conclusions

ROV survey showed that the seabed environment offshore Nigeria (750-1350m water depth) was extremely diverse, containing several habitats from sedimentary plains to steep rocky slopes. The visible seabed fauna were generally abundant (0.3 animals m-2) and diverse (>69 species). Faunal communities varied in density and composition across the habitat and depth range. Many species were previously described; however, surveys revealed several potential new species and ROV traps captured a confirmed new species of amphipod crustacean. Sediment samples collected provide valuable pre-drilling baseline data, which will allow assessment of the extent and magnitude of future environmental disturbance from operations. Temporally replicated temperature and salinity depth profiles captured the thermocline's seasonal movement in much greater detail than previous observations.

Significance of Subject Matter

The significance of this biodiversity assessment includes:

Data collected provided a suite of high-resolution baseline measurements which are invaluable for future impact assessment. Use of ROVs during stand-by time enabled rapid low cost data collection. Approach facilitates initial environmental evaluation and longer-term monitoring of hydrocarbon exploration and production areas. Results increase the knowledge of the environmental conditions of deepwater offshore Nigeria and indeed West Africa. This survey provided important information on offshore biodiversity to the Nigerian Regulatory Authorities (Federal Ministry of Environment and Department of Petroleum Resources) thus enhanced regulatory support for the drilling project.