bluuebunny/crossref_metadata_2025_split huggingface dataset:
Validating of the Reservoir Connectivity and Compartmentalization with the CO2 Compositional Gradient and Mass Transportation Simulation Concepts
Authors: Daungkaew Saifon , Mullins Oliver , Johan Zailily , Lehne Eric , Zuo Julian , Sinnappu Suresh , Pfeiffer Thomas , Lin Tan Giok , Tunku A Muthalib Tunku Indra , Hong Teh Yat , Rameli Hazwani Bt , Ludwig John T 
Published: October 2011

Abstract
More than 40% of the world's conventional gas reserves are in reservoirs that contain significant amounts of H2S and CO2. The presence of these gases results in a number of challenges for the Field Development Plan (FDP). For a field with multiple fault blocks with unknown fault transmissivity, a key challenge is to understand the field connectivity and compartmentalization which impacts the ability to drain their reserves.
This paper presents a comprehensive study to understand reservoir connectivity in a gas and oil fields located in South East Asia. This particular field has variation of the CO2 even in the same zone ranging from less than 10% to more than 80%wt. A key for production strategy and facility design is to be able to accurately quantify CO2 in each reservoir is. Initially, the CO2 study aimed to quantify the CO2 content for each reservoir using an advanced Downhole Fluid Analyzer (DFA), and then to use the DFA measurement as well as the available PVT data from nearby wells to understand reservoir connectivity through the use of a compositional gradient concept. Reservoir fluids that deviated from the compositional gradient were considered to not be in equilibrium. In addition, the use of a PVT thermodynamic calculation with a non-isothermal solution resulted in a possible identification of the CO2 charging location.
Although the geochemistry study was conducted to understand the source of CO2 and hydrocarbon isotopes, it did not provide a conclusive result of the reservoir connectivity. As expected the hydrocarbon had a different charge source compared to the non hydrocarbon gases. Since the geochemistry study was inconclusive, a mass transportation simulation was performed to understand the reservoir connectivity and this information has had a great impact on understanding the production mechanism of this field.
This paper provides a systematic process to understand the reservoir connectivity by using the integrated reservoir data such as pressure, DFA, PVT fluid properties, geochemistry, as well as the geological and geophysical interpretations of the reservoir. This paper offers an efficient way for reservoir characterization for proper field management for an important hydrocarbon discovery in South East Asia.
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.