bluuebunny/crossref_metadata_2025 huggingface dataset:
Effects of Tower Motion on Packing Efficiency
Authors: Cullinane J. Tim , Yeh Norman , Grave Ed
Published: September 2011

This work reviews the major published studies, both theoretical and experimental, that address the impact of wave motion on packed tower performance. Current practice is to add excess packing to guarantee the required separation is obtained, though there is little data available to derive a safety factor for packing height. This work highlights deficiencies in the current knowledge base and analyzes general trends to address common misconceptions about tower design for floating production.

Tilt and motions imposed on a fractionation column have a significant impact on product specifications due to reduced packing efficiency. Improved awareness of motion impacts will assist the analysis of tower design and allow feedback to the process design. Identifying gaps in available data shows limits in the current understanding and allows the development of appropriate simplifying assumptions.

The current understanding of towers in motion allows only very basic design rules and the safety factor for packing height in literature varies from 1.1 to 2.0. This provides little confidence in the ability to predict packing efficiency for floating production.

Static tilt is more detrimental to liquid distribution than motion at a given amplitude. Still, liquid maldistribution from motion approaches that of static tilt as the period increases. Liquid sloshing, often cited as a significant concern, is a relatively minor contribution to maldistribution except for short periods and tall towers. The relative bed size has a significant impact on liquid maldistribution, limiting the recommended maximum bed height:column diameter to 2 – 3 to maximize the efficiency.

Approach to equilibrium is often overlooked as the major determinant of sensitivity of efficiency to maldistribution. Separations that operate near equilibrium are more sensitive to maldistribution than services with a large driving force. Thus, distillation towers are generally more sensitive to motion than absorbers and sensitivity may vary over column height. Recommendations are provided for a bed-by-bed analysis and feedback to the process design.

Floating production units require additional complexity and conservatism in tower design. An improved awareness of motion effects on towers, and the factors involved, will lead to improved designs and a reduction in the cost of floating production facilities.
Deepwater Multiphase Liquid Sampling Using Multiple Application Reinjection System (MARS)
Authors: Hall G.. , Gordon A..
Published: September 2011

This paper provides an overview of a new methodology of capturing a physical sample of produced fluid from a Subsea Tree or Manifold in deep water and recovering it for laboratory analysis.

It describes both the sampling & recovery equipment, together with the associated intervention technology, MARS (Multiple Application Re-injection System). The MARS system allows a coaxial flowpath to be introduced into the wellstream without having to recover permenant subsea infrastructure.

Being able to take liquid samples from individual wells subsea before they are comingled into the pipeline enables production optimisation on a number of fronts including:

Flow-meter calibration (affected by water cut / salinity). Tracer detection (understanding the reservoir) Need for Scale squeeze (barium content) Well fluid composition (per well)

The interface technology has already been tested on other deepwater subsea applications, including multiphase pumping, metering and well stimulation. The sampling technology is now proven following testing at the National Engineering Laboratory, East Kilbride, Scotland using both the multiphase and wetgas flow loops. The testing program validated the technique, optimised the design and determined the operating envelope across a wide variety of flow conditions.

Application engineering is underway for a project in the Gulf of Mexico.

The system provides access to valuable data which can be used to optimise production.
Planning and Conducting Well Tests in Deep and Ultra-Deep Water to Mitigate Potential Risks and Justify Expense for the Operator
Authors: Wendler C.. , Maia C. Tigre
Published: September 2011

Well testing is a critical part of potential production assessment in deep and ultra-deep water well development. When target reservoirs produce heavy oil, gas, and condensate, or are high pressure/high temperature (HP/HT) environments, test designers in the operating company must not only focus on safety and risk mitigation for the operator, when planning these tests, but also must assure that the tests will gather enough data to justify the operational expense and potential risks inherent to these types of environments.

Deep-water production usually requires prolonged periods of low temperature and heat loss, which can affect production or result in hydrate formation. Intervention can be problematic and costly. Fluid volumes, well and water depths accessed can increase well-control time and expense for the operator. Also, since these well tests are conducted from mobile vessels, the alarm and subsea equipment philosophies are critical to the enhancement of safety and risk mitigation. Well-test design and string configuration must have flexibility but still must be capable of efficiently controlling the conditions listed above.

Obviously, these and many other issues must be fully understood by the operator if the program plan, equipment, and methodology have the capability to assess the challenges, ameliorate the risks, and provide contingencies for unexpected events that could occur.

This paper explores these issues as well as appropriate methodologies for mitigation. The merits and limitations of various solutions will be considered along with the basic philosophy of equipment consideration. Lessons learned from actual cases will be used to compare consequences of inadequate preparation to the benefits of proper design.

Also explained will be why particular methods and equipment should be used and why others are less desirable. Lessons learned and their application will be discussed, including:

Red, yellow, or degraded status decision making during dynamic-positioning (DP) vessel testing Coiled-tubing usage criteria Defining cushion-type criteria Defining mud-type criteria Hydrate prevention and mitigation Importance of obtaining dynamic reservoir data efficiently and economically without risking the environment and personnel safety.
Meeting the Environmental Challenge with Technology
Authors: Morrison Pete
Published: September 2011

All industries are being challenged to demonstrate corporate and environmental responsibilities, none more so than those of our own sector. We have taken a holistic approach to this challenge by developing waste monitoring systems to support the drilling waste processing service. For the first time, customers can now monitor their drilling waste online with near-real-time data on locations, tonnage, analysis and cumulative costs, thereby ensuring accuracy and regulatory accountability at all times.

Seamless integration of multiple existing IT and drilling and evaluation analyses systems provides cradle-to-grave monitoring and traceability of drilling related waste. This enables waste-processing staff, customers and regulatory bodies to have full visibility of wastes at various stages in the waste-management process, not only from the environmental perspective but also the estimated costs of processing. The customer can now make informed decisions while drilling to reduce the environmental impact and cost of processing the drilling waste.

The integration of existing systems and common data standards such as WITSML delivers an innovative technology solution to the waste-management process and a model for utilizing multiple existing systems across the enterprise, reducing implementation costs and the resource footprint.

By having this high level of visibility to locations, tonnages, analysis results and cumulative cost tracking, the information reconciliation and confirmation of by-product inertness protects both the environment and our customers.

Our challenge has been to elevate the industry's environmental visibility of their waste products to a new level. This will benefit our customers by satisfying the most stringent environmental protection agency requirements. Customers will have a clear chain of custody for their wastes and at the same time lay the benchmark to take them into a future of ever-tightening industry regulations and environmental awareness.
Mechatronics Technology in Drilling Operations Used to Enhance Safety
Authors: Karnugroho Ardia , Nas Steve , Toralde Julmar Shaun , Prajogo Tutuko
Published: September 2011

According to Wikipedia, "mechatronics" is the synergistic combination of mechanical engineering, electronic engineering, computer engineering, control engineering, and systems design engineering in order to design, and manufacture useful products. The combination of these technologies is now actively being used to enhance the safety of drilling operations.

This paper presents an overview of how mechatronics is now used in the oil & gas industry to significantly enhance the safety of drilling operations. In the drilling industry this technology is known as managed pressure drilling.

Automating the control of bottom hole pressures whilst drilling the well significantly enhances the safety of the drilling operation. Using control technology combined with accurate sensors and additional equipment when drilling provides an unprecedented level of detection and control of the well whilst it is being drilled. This in turn enhances the efficiency and safety of the drilling operations.

This technology has been used on a number of high pressure high temperature wells and it is now being used on deepwater wells to provide early kick detection as well as riser gas handling.

This paper demonstrates the use of mechatronics in the drilling process and the applications of managed pressure drilling in deepwater and high pressure wells.
Transforming a Digital Reservoir System into Reality: How to Get Things Right
Authors: Castillo D. A. , Bratovich M. , Early R.
Published: September 2011

The geophysical, geologic, engineering and operational data that makes up the digital spectrum of information in the energy industry certainly has value when analyzed within its respective discipline. Elevating this value to create attainable dividends in the context of the overall reservoir development will depend upon our relentless commitment to integration. This will be especially important as the targeted reservoirs become more complex, volumes smaller, environments more challenging and our need to intervene to enhance production becomes an integral part of field management.

An incomplete or incorrect understanding of the earth model (reservoir and overburden) can result if we fall short in utilizing all data gathered, or ignore or incorrectly interpret the information at hand. This is especially true in today's world of lean resourcing strategies and pressures of reduced decision cycles times. The value of integrating and rigorously interpreting the wide range of data collected from modern technologies and optimizing or automating the workflows can become a measured reality that serves to maximize reservoir performance during a field development program.

As scientists and engineers who are charged with responsibly exploring and exploiting earth's resources, understanding the geomechanical and flow dynamics and petrophysical rock character existing over the entire life-cycle of the reservoir, especially during production and field rejuvenation, positions us to better use modern drilling and completion technologies for optimal well planning and reservoir drainage. Constraints on how the reservoir, overburden, faults and natural fractures behave in time and space will be directly linked to how well we have integrated our data to understand the reservoir and how well we execute a fine-scale production monitoring program.

Integrating this expected influx of digital information will require an industry-wide paradigm shift in how we manage, evaluate and interpret information. The purpose of this paper is to use case studies to describe the critically important role geomechanics, petrophysics and reservoir performance analysis plays in an integrated interpretation with the intent to develop and execute effective management strategies.
A New Method of Acquiring Open Hole Logs in Unconventional Wells
Authors: Reischman Richard L.
Published: September 2011

Open hole logging of highly deviated and horizontal wells is now becoming more accepted due to a recently developed conveyance and acquisition system that can greatly reduce the cost and risk associated with running logs in these types of wells. Conventional log measurements including resistivity and porosity, which in many cases may not have been previously economical to obtain in lateral wells, can now be used to delineate the needed basic reservoir properties for planning completions and future drilling designs.

The method employs a newly engineered ultra slim toolstring that is designed to pass through the drill pipe and a specially designed hollow PDC bit into open hole. Data can then be obtained beyond the bit in memory while tripping out with the tools on pipe. Lost in hole risk and the higher cost of using other more expensive methods, such as LWD, can be minimized by using the drill pipe and bit to safely acquire the data and retrieve the tools if necessary. Circulation of the well fluids and pressure control can still be maintained throughout this process. A brief overview of the conveyance method and acquisition tools will be presented along with log examples from some of the common unconventional plays that outline the applications of this data.
Global Model for Fracture Falloff Analysis
Authors: Marongiu-Porcu M. , Ehlig-Economides C. A. , Economides M. J.
Published: September 2011

Hydraulic fracturing is undeniably the crucial technology involved in the development of tight and/or unconventional gas reservoirs. The fracture geometry and pumping execution, as well as the well architecture, can be designed to maximize the well productivity, provided the reservoir permeability is known. Because it is difficult to estimate permeability from conventional pressure transient tests, various authors have shown how fracture-injection/falloff tests designed for final fracture design calibration (i.e. estimation of closure stress, leak-off coefficient and fracture fluid efficiency) can be used to estimate reservoir permeability as well.

This paper presents a new comprehensive model for the analysis of fracture falloff, following a step-rate or constant rate injection test. The derivative of the falloff pressure change with respect to the logarithm of superposition time shows a progression of straight trends that include a newly introduced elastic closure-dominated flow enabling determination of the closure stress (3/2 slope), post-closure formation-linear flow (1/2 slope) and infinite-acting pseudo-radial (0 slope). This model provides a robust complete assessment tool that allows quantification of all fracture parameters (closure stress, fracture extent, leak-off coefficient and fracture fluid efficiency) as well as reservoir permeability, provided that enough time is allowed for the falloff to reach pseudo-radial flow regime. Both oil and gas reservoirs can be effectively evaluated.

While the approach is leveraging well-accepted pressure transient analysis methods, the inclusion of elastic closure-dominated flow is new. This model can be used to design fracture-injection/falloff tests that would allow determination of all the involved parameters, including reservoir permeability. Field data validate the model and demonstrate the value of this approach.
Rate-Normalized Pressure Analysis for Determination of Shale Gas Well Performance
Authors: Song Bo , Ehlig-Economides Christine
Published: September 2011

The horizontal well with multiple transverse fractures has proven to be an effective strategy for shale gas reservoir exploitation. However, to improve the well design it is important to quantify the reservoir permeability and the extent of the stimulated reservoir volume (SRV) defined by the created hydraulic fractures.

Rate-normalized pressure (RNP) is easily computed from production data and is more straightforward to interpret than pressure normalized rate. Pseudolinear flow before pressure interference happens between two adjacent transverse fractures, seen as a ½ slope trend in the RNP derivative, and pseudo pseudosteady state, seen as a straight trend with slightly less than unit slope, are key to the analysis. When only pseudolinear flow appears, a minimum extent for the SRV is indicated as well as a maximum value for the shale permeability. The appearance of pseudo pseudosteady state flow provides an estimate for the pore volume of the SRV and a minimum value for the shale permeability. When both pseudolinear and pseudo pseudosteady state flow regimes appear, permeability and the average half-length and spacing of created fractures can be estimated.

We illustrate the analysis procedure with field data from key shale gas plays. Estimates for both the expected ultimate recovery and recovery efficiency as a fraction of the gas in place in the SRV are possible using this interpretation technique. Sensitivity of the analysis to uncertainties in shale thickness, porosity, and adsorption parameters are explored.
Holistic Drilling Fluid and Waste Management in the Fayetteville Shale
Authors: Mabile Mark , Garner Steven , Broussard Barry , Smith Richard
Published: September 2011

Successful application of a Holistic Fluid Management (HFM) program increased drilling fluid performance and reduced waste and costs in Southwestern Energy's (SWN) unconventional Fayetteville Shale gas project in Arkansas from January 2009 through December 2010. The HFM program significantly reduced environmental impact by lowering drilling waste volumes nearly 45 percent, while reducing drilling fluid and waste costs 36 percent. Reduction in Combined Costs (fluid systems, solids control equipment and waste disposal) totaled $69 million while drilling 705 wells with oil-based mud (OBM) over 4,200,000 ft during the 24-month study period.

The holistic management of drilling fluids, solids control, waste management and disposal of drilling waste has been the subject of considerable effort over the last decades. The process required to manage these projects has been well documented, along with successful case histories.

HFM projects have an improved chance of success when expectations, goals, and responsibilities are well-defined, communicated, and understood by all participants. The financial objectives of the providers of fluid-related services may not always align with those of the operator. This hurdle is further complicated by the limited availability of seasoned well site service personnel with the knowledge, authority, and experience to be proactive while implementing the required changes.

Critical components of an effective HFM program are an unbiased and dedicated project team, and the development and communication of the right goals and key performance indicators (KPIs).
Shale Gas-in-Place Calculations Part II — Multi-component Gas Adsorption Effects
Authors: Hartman Robert C. , Ambrose Ray J. , Akkutlu I. Yucel , Clarkson C. R.
Published: September 2011

Recent studies have shown that shale gas industry is incorrectly determining gas-in-place volumes in reservoirs with a large sorption capacity by not properly accounting for the volume occupied by the adsorbed phase. Scanning electron microscopy has discovered nanopores in organic-rich shale with sizes typically in 3–100 nm range; adsorption data show presence of smaller pores and micropores (< 2 nm) as part of the predicted pore size distributions. At pore diameters of this scale the adsorption potential is high and thus the fractional pore volume occupied by adsorbed gas is often substantial. Hence a portion of the total pore volume would be occupied by the adsorbed gas and not available for the free gas molecules. In SPE 131772 a volumetric method, which accounts for the pore volumes occupied by the adsorbed and free gases, has been proposed based on single-component Langmuir adsorption model. In SPE 141416 we recognized the importance and impact of multi-component gas adsorption potential and adsorbed gas density when calculating gas-in-place estimates. We combined the widely used yet thermodynamically inconsistent Extended Langmuir model with volumetrics and free gas composition to formulate a new gas-in-place equation that accounts for the pore space taken up by a multi-component adsorbed gas phase. This paper extends the discussions on the adsorption layer effect of multi-component natural gases. The approach is based on thermodynamically-consistent ideal adsorbed solution (IAS) model to accurately predict adsorbed gas storage capacity for gas mixtures. We expanded on our previous work, where we calculated single-component adsorbed-phase density using molecular modeling and Monte Carlo simulation methods, and propose a new equation-of-state-based analytical approach to predict the adsorbed-phase density of a mixture. In concert, the model improves accuracy of the gas-in-place equations needed to account for the pore space taken up by a multi-component adsorbed phase. The new method yields total gas-in-place predictions, which suggest that an adjustment is necessary in volume calculations, especially for gas shales with high C2+ composition and high in total organic content. The new method is therefore recommended for shale gas-in-place calculations.
Using Moment Tensors to Determine the Effectiveness of Hydraulic Fracture Stage Spacing
Authors: Prince Marc , Baig Adam , Urbancic Ted , Buckingham Katherine , Guest Alice
Published: September 2011

Hydraulic fracturing is performed in tight gas shales in order to create extensive fracture networks throughout the reservoir. Often the distance between injection zones is selected in order to maximize the fracturing of the reservoir and minimize the amount of reservoir that remains untreated. Recently, the deployment of three dimensionally distributed geophone arrays allows for Seismic Moment Tensor Inversion (SMTI). Using SMTI, the rock failure mechanisms can be examined both spatially and temporally, showing how the hydraulic fracture treatments interact with each other.

When events from a hydraulic fracture stage grow into previously fractured zone, there are three possible interactions: the fracture network in the previously fractured zone can dialate; the fracture network in the previously fractured zone can experience equal opening and closing result in little to no increase the effective fracture network; or the previously activated fracture network can experience more closure than opening, resulting in reduced productivity in the reservoir. One parameter that can be calculated from the SMTI is the cumulative volumetric strain which provides a parameter that reflects whether the fracture network is dominantly opening or closing over the course of the injection program.

In this study, we examined microseismicty from three stages of a multistage hydraulic fracture treatment in a shale gas reservoir in North America. The SMTI analysis is performed and failure mechanisms are calculated for events over the course of three subsequent stages. From the failure mechanisms, the cumulative volumetric strain is calculated and plotted versus time over the duration of each of the stages. For each of the three stages, the cumulative volumetric strain is compared and the dominant fracture state (opening or closing) is determined. The results suggest that interconnectivity of the hydraulic fracture treatments is complex and can lead to increases or decreases in the effective fracture network.
Production Acceleration or Additional Recovery? - A Look Back at Three Published Field Trials to Determine the Long Term Benefits of Improved Fracture Treatments
Authors: Blackwood K. , Handren P. , Chapman M. , Palisch T. , Godwin J.
Published: September 2011

There is no doubt that improved frac designs can increase production rates from many reservoirs. However, do these changes merely accelerate recovery, or is incremental production gained by changing the fracture design?

Results from field trials are often published within a year (or even less!) of the initial design changes, and EUR projections are required to forecast the long-term economic impact. This paper will document a re-examination of three tight gas case studies published in the past ten years to determine whether recovery projections were accurate. Included are a review of field studies performed in the East Texas Haynesville Lime, the West Texas Canyon Sand, and the East Texas Cotton Valley-Taylor Sand. The original studies in these tight gas formations were specifically performed to assess the impact of increased fracture conductivity on production. In all cases, the initial analyses documented that increasing conductivity appeared to increase production and recovery.

By revisiting these case studies using extended production data, a more rigorous determination of recovery and associated economics will illustrate whether recoverable reserves are increased from tight gas reservoirs with careful modification of fracture designs. This paper will speculate on the mechanisms that may allow incremental reserves to be captured from some reservoirs, and will evaluate the uncertainty of reserve forecasts constructed from less than one year of production data. This summary should be of interest to any engineer who must estimate the recovery impact of completion changes when only limited production data is available.
Simulation of Two-Phase Flow in Carbon Dioxide Injection Wells
Authors: Pekot Lawrence J. , Petit Pierre , Adushita Yasmin , Saunier Stephanie , De Silva Rohan
Published: September 2011

To model a variety of potential operating conditions in pure carbon dioxide (CO2) injection wells we performed a multiphase transient well flow simulation study. A thermal reservoir simulator was also used to estimate the extent of reservoir cooling and the variation of injectivity index to be expected from injection of cold CO2.

Depleted gas reservoirs are potentially attractive targets for CO2 but their low pore pressure results in low bottomhole injection pressure and potentially two-phase flow regime in the wellbore. Other authors have noted the possible implications of this condition; however, none have addressed the issue using transient flow simulation.

A vertical wellbore model was built in a multi-phase transient flow simulator, assuming representative Southern North Sea conditions. To investigate wellbore profiles of pressure, temperature and CO2 liquid hold-up, parametric as well as thermal reservoir simulations were performed. The latter simulations integrated the bottomhole conditions observed in the wellbore model.

Results show that pure CO2 injected at the wellhead may vaporize or condense as it travels down the tubing, experiencing continuous changes in pressure and temperature as dictated by its change in enthalpy. However, sudden vaporization or condensation is not predicted by the simulator. Two-phase flow cases resulted in stable injection conditions. Well injectivity index varied significantly with injection fluid temperature and pressure, but the extent of reservoir cooling away from the wellbore was limited. This suggests that onerous processing to avoid a two-phase flow regime in CO2 injection wells, such as pre-injection heating or downhole choking may not be necessary at the injection start-up into a depleted gas reservoir.
Offshore Replacement of a Damaged FPSO Fairlead
Authors: McKeown Richard , Bisset Alastair , McKeown Stephen
Published: September 2011

In 2010, the operator completed the successful replacement of a damaged fairlead within the mooring system of its FPSO (Floating Production, Storage and Offloading). This is believed to be the first time that a fairlead has been changed-out in situ on any floating installation in the North Sea. This was a complex operation involving many different vessels and topsides activities. This paper details how the damaged fairlead was safely secured and replaced.

The replaced fairlead was deemed irreparable because one of the axle retaining plates and its associated bolts were missing. However, after further ROV (Remotely Operated Vehicle) inspections, it was discovered that the remaining seven fairleads were also displaying symptoms of the same failure mode i.e. axle retaining bolts were missing or found loose placing further strain on the remaining bolts.

The condition of the axle retaining bolts was deteriorating and the operator was unsure when the next catastrophic failure could occur. Therefore, ROVs were used to secure the seven failreads as effectively as possible by replacing/tightening bolts and air divers were mobilized to install pins to apply additional clamping force while allowing access to the original retaining bolts. The original bolts were replaced and segregated so that they could be analysed onshore.

An investigation was undertaken to understand the failure mode of the FPSO fairleads. It was hoped to compare the differing levels of damage to different factors such as weather, mooring line catenaries, etc… to determine which factors are significant.

It was concluded that the bolt damage was mainly the result of design issues. A combination of QA/QC (quality assurance/quality control) issues, environmental and operating conditions could explain the differing levels of fairlead damage.

The integrity of the mooring system was severely under threat throughout. Plus, replacing a fairlead is a long and costly exercise, therefore early identification of fairlead bolt issues and intervention is extremely valuable.
Experimental Investigation of Near-Miscible Water-Alternating-Gas WAG Injection Performance in Water-wet and Mixed-wet Systems
Authors: Fatemi S. Mobeen , Sohrabi Mehran , Jamiolahmady Mahmoud , Ireland Shaun , Robertson Graeme
Published: September 2011

Laboratory data on WAG injection for non-water-wet systems are very limited especially for near-miscible (very low IFT) gas-oil systems, which represents injection scenarios involving high-pressure hydrocarbon gas and CO2 injection. Simulation of these processes requires thre-phase relative permeability (kr) data. Most of the existing three phase relative permeability correlations have been developed for water-wet conditions. However, majority of oil reservoirs are believed to be mixed-wet and hence, prediction of the performance of WAG injection in these reservoirs is associated with significant uncertainties. Reliable simulation of WAG injection, therefore, requires improved relative permeability and hysteresis models verified with reliable measured data.

In this paper, we, first, report the results of a comprehensive series of coreflood experiments carried out in a core under natural water-wet conditions. These included water injection, gas injection and also WAG injection. Then, to investigate the impact of wettability on the performance of the above injection strategies, the wettability of the same core was changed to mixed-wet (by aging the core in an appropriate crude oil) and a similar set of experiments were performed. WAG experiments under both wettability conditions started with water injection (I) followed by gas injection (D) and this cyclic injection of water and gas was repeated (IDIDID).

The results show that in both the water-wet and mixed-wet cores, the performance of WAG injection is better than water injection and gas injection alone. Changing the rock wettability from water-wet to mixed-wet significantly improve the performance of water injection. Under both wettability conditions (water-wet and mixed-wet), the breakthrough (BT) of the gas during gas injection happens sooner than the BT of water in water injection. Ultimate oil recovery by gas injection is considerably higher than that obtained by water injection in the water-wet system, while in the mixed-wet system gas injection recovered considerably less oil.
Remote Operations—A Remote Possibility, or the Way We Do Things ‘Round Here?
Authors: Cramer Ron , Hofsteenge Hetty , Moroney Tom , Gobel Derek , Akpoghiran Fidelis , Murthy Ajith
Published: September 2011

Shell aspires to maximize unattended operations for all upstream E&P "green" and "brown" field assets using the appropriate level of automation. The benefits associated with down manned operations include the following:

Reducing staff exposure to travel hazards e.g., driving, sailing and flying Reduce staff exposure to process hazards at the well site and drill floor Increased production due to continuous monitoring and optimization by expert staff CAPEX saving due to elimination of unnecessary facilities such as process simplifications and reduced number of offshore beds OPEX savings due reduced travel and reduced logistics Increased staff productivity due to less time spent travelling Reduced GHG emissions as a consequence of reduced travel and improved process efficiency

The underlying premise is that the E&P process should as much as possible be monitored and controlled from a remote monitoring/control room staffed by the most experienced and capable people.

For "green field" facilities the basic design concept that we aspire to is unattended as the norm and attended as an exception that has to be clearly justified.

For "brown fields" we aspire towards as much as possible reducing attendance, again by monitoring and controlling from remote control centers.

This paper will describe the following:

Shell's overall remote operations strategy Technologies associated with remote operations, inclusive of production deferment reducing techniques such as data analytics and well/reservoir surveillance Shell guidelines associated with remote operations EP remote operations experiences in a number of different assets in Europe, USA and Africa

This paper demonstrates that, for Shell, remote operations is not a remote possibility, but is in the process of becoming a reality across our global upstream operations.

This paper was also prepared for presentation at the SPE Annual Technical Conference and Exhibition held in Denver, Colorado, USA, 30 October–2 November 2011 as SPE-145293-MS.
Reservoir Surveillance and Successful Infill Well Delivery in a Mature Asset
Authors: Zett Adrian , Mukerji Parijat , Ward Mary , Pearse Chris , Houliston Dawn
Published: September 2011

Production Petrophysics plays a key role in reservoir surveillance and field management. This is particularly true for mature assets which present several challenges related to fluid contact movement, connectivity of reservoir layers and well productivity. Identification of infill targets therefore requires an integration of all sub-surface data. This paper presents examples from a mature North Sea field where cased-hole surveillance helped minimize risks in a high cost infill project. The Machar field, located in the UK Central North Sea is a fractured Cretaceous chalk and Palaeocene sandstone oil reservoir. The field development has been carried out in a phased manner due to a high degree of reservoir uncertainty, especially in the eastern flank. Enhancing the seismic sufficiently to fully assess prospects on the east became a priority, and ultimately led to drilling the east flank of the field in 2008.

Machar is a subsea field development and therefore petrophysical surveillance has been restricted due to limited well access and logistical challenges. During the infill drilling, it was therefore decided to use the opportunity and capture cased-hole saturation and production logs in existing wells. This data enabled the asset teams to understand fluid displacement mechanisms and upon integration with LWD and other logs provided the basis for the side track strategy. In particular, location of the imbibition flood front, fracture conduits and differentiation between formation and injection water were critical in the delivery of a successful producer.

Two wells have been drilled on the eastern flank, one in 2008 and another in 2010. Baseline petrophysical surveillance was part of the data acquisition program in both wells. The initial objective was to use such data in Time Lapse mode with later surveillance. However, in-depth work identified immediate use when integrating with LWD and Wireline data.
CO2 Leakage Prevention Technologies
Authors: Eke Paul Emeka , Naylor Mark , Haszeldine Stuart , Curtis Andrew
Published: September 2011

A central challenge of both scientific and regulatory interest is how to ensure carbon dioxide (CO2) is securely contained within a storage site. The fate of CO2 in the subsurface describes the range of processes that progressively trap the CO2. Pure phase CO2 can be trapped within the pore space as (i) residual saturation, and (ii) capillary trapping where the buoyancy forces exerted by a vertical column of CO2 are not sufficient to overcome the capillary forces either within the reservouir rock or to overcome the caprock. Aside from the physical trapping of free CO2, it can be trapped as an aqueous phase. An alternative to injection of pure phase CO2 is to inject CO2 saturated waters which are denser than the unsaturated formation waters thus eliminating the problems associated with buoyancy. Further, in order for the CO2 to be locked away geochemically as mineral trapping, it must first enter an aqueous phase in order for it to be reactive.

Here we explore engineering technologies for enhancing the dissolution of CO2 in formation fluids to mitigate leakage and minimise the risk of CO2 escaping from the storage site. Conceptual process engineering and design of CO2 injection systems downstream were performed with primary aim of rendering integrated injection strategies suitable for use in enhancing permanent storage of CO2 in deep geological formations.

The results of the application indicate that the strategies speed up CO2 dissolution and immobilisation as the period of time needed to achieve immobilisation in the subsurface formation is enhanced by the surface processes engineering. The immobilised CO2 will remain indefinitely in the storage zone even if the integrity of the caprock is not intact.

These innovative engineering technologies provide leakage prevention opportunities which are fundamental to addressing long-term risk management and monitoring issues for CO2 storage sites.
Cross Industry Hydrocarbon Release Analysis
Authors: Li Amy
Published: September 2011

This paper presents the recent analysis results of offshore hydrocarbon releases occurring on the United Kingdom Continental Shelf (UKCS) between 2008 and October 2010. The analysis includes the type of hydrocarbon released, the operating mode during which releases occurred, the release sites, age of installations, type of installations (manned and unmanned; Floating Production Storage and Offloading vessels [FPSOs], Floating Production Facilities [FPFs] and fixed installations) and the underlying causes of the releases. This paper aims to assist the industry to identify where it can best place its resources to reduce the number of hydrocarbon releases.
Managing Process Safety to Enhance Business Performance
Authors: Cockburn-Evans John
Published: September 2011

The oil and gas industry has had a long history of mixed safety performance. And yet, safety has always been an imperative due to the sometimes rather extreme hazards faced by the employees. Recognising this, the industry has made great strides in improving safety performance, as can be seen by the reduced lost time injury rates. The industry has also made remarkable progress in advancing technical and technological capability, but continues to face challenges in preventing major incidents. Investigations from these major incidents have a common thread: a relatively low level of appreciation of risks, muted reactions to near misses and some degree of complacency. In all cases, the origin can be linked to the level of commitment stemming from the highest layers of management.

The hazardous and complex nature of oil and gas extraction and processing is readily apparent, and management within the industry is making good progress in fully recognizing its obligation to make responsible decisions. The type of decision-making required necessitates a structured and systematic way to appreciate risks, to create a culture of learning and to maintain focus and determination to counter process risks in the absence of major crises. Through its experience, DuPont developed a process safety management (PSM) system based on best practices. This system has helped to achieve operational excellence, manifesting in increased productivity, higher quality of deliverables, reduced waste, lower operational costs and enhanced business performance.

This paper will provide recommendations on improving the safety context, as well as implementation of mechanisms that ensure sustainability. Moreover, this paper will discuss specific actions and processes based on DuPont best practices that can be implemented by oil and gas companies to reduce risk and streamline operations. Benefits of this system extend beyond avoidance of catastrophic events and their associated costs. It has been shown that PSM has contributed to increased productivity, higher quality, reduced waste and lowered operational costs.

The extraction of oil and gas is a highly technical mechanical operation that involves volatile and corrosive substances in often extreme conditions. Repetitive acts can lead to complacency, increasing operational risk. Through proper administration of process safety management, it is possible to protect personnel from injury and prevent significant environmental harm, property damage, and business losses, while furthering the ability to achieve performance objectives.
The Role of Asset Integrity and Life Extension in Major Accident Prevention
Authors: Ritchie David M
Published: September 2011

Duty holders and operators of major hazard assets should have in place the required processes, programmes and procedures which coherently:

Prevent major accidents; ensuring risks from major hazards are reduced to as low as reasonably practicable Ensure asset integrity is a continuous process throughout an asset's life Ensure asset life extension is properly managed using defined processes and procedures

This paper describes how, collectively, these processes, programmes and procedures are aligned to a major accident prevention process which is a core element in the management of an asset at all stages of its life cycle.

The primary goal is to ensure that plant and equipment does not, and is not allowed to fail in such a way as to cause or substantially contribute to a major accident.

The requirement to manage assets throughout their life including any life extension period should be mandated by company policy and standards which in ConocoPhillips case recognises the design, operation and maintenance of an asset should be such that its integrity is preserved at an acceptable level of risk throughout its operating life.

Asset life extension is a process that begins when an asset's components wear out, requiring maintenance or repair to maintain a satisfactory operating condition. This begins soon after the asset enters operation for the first time and continues throughout the life of an asset.

However, with increasing age, unchecked asset degradation can become widespread and gradually escalate to a point where significant restoration is required. Consequently, major accident risks may be increased requiring an asset operator's management system to be carefully designed to contain them.

By embedding the Major Accident Prevention Process in the way we design and manage our assets, we ensure that asset integrity is a continuous and forward looking process that supports the case for asset life extension.
The Maule Field: An Economic Small Field Development
Authors: Pyle Jeff , Koster Klaas , Rose Phil , Barker Gregg
Published: September 2011

Apache discovered the Maule field in October 2009 with the 21/10-A52 wellbore drilled from the Forties Alpha production platform. The discovery of a 14m TVD net oil column in Eocene aged Brimmond sands led to the development of the Maule field under the UK government's small field allowance scheme. The field was taken from completion of the discovery well to first oil from a horizontal production well in under 9 months.

The Maule field is located on the western margin of the Brimmond Formation turbidite fairway where re-mobilised sands are also present. Steep dips as seen in the development well and steep seismic features indicate that the Maule field reservoir was formed by remobilsation of Brimmond sands.

The A52 exploration well was drilled on the basis of a seismic amplitude anomaly. This seismic data along with LWD density image data was used to successfully place the horizontal production well which accessed a 114m MD pay section and flowed in excess of 11,500 bopd. A 2010 4D snapshot taken in early July 2010, 5 weeks after production started, identified the source of the well's rapidly increasing water-cut and identified further infill locations.

Despite modest production for an offshore North Sea development the first Maule producer has been an economic success for Apache as a result of integrated subsurface technical work, drilling performance, small field allowance incentives and a sense of urgency.
Increasing Reliability of Cutting/Pulling Casing in a Single Trip
Authors: Hekelaar Stephan , Gibson Kenneth , Desai Praful
Published: September 2011

This paper discusses the tools, technology and methods developed to significantly reduce pipe cutting and recovery time in subsea plug and abandonment operations and in the slot recovery program for existing platforms.

Conventional apparatuses and techniques for cutting and extracting well casing involve multiple trips downhole to run and retrieve the cutting and spearing equipment, because the required tools do not function cooperatively. In certain slot recovery operations, cutting and pulling the casing may be difficult due to firm cement bond, barite settling from drilling fluid in the annulus, or both. Accordingly, such slot recovery operations require cutting the casing several times to locate a friction free point for safe extraction of the severed casing resulting in multiple trips.

The authors describe a recently developed pipe cutting system with multiple sets of cutters which can be selectively activated while the tool is downhole. When one set of cutters wears down, a replacement set can be selectively activated to resume cutting actions. The tool currently has three sets of cutters; however more sets can be added. Also, each set of cutters feature knives dressed with novel inserts made from a specially formulated compound which extends cutter life. Each set has a positive knife return mechanism to ensure full collapse. The tool also enables pressure to be monitored from the surface by means of an indicator device, which registers a pressure drop at the rig floor to indicate a cut has been completed. Additionally, the spearing device can be run in the same drill string and selectively activated to retrieve casing after it is severed.

North Sea field runs involving slot recovery programs in which operators faced stuck casing that required several cuts to locate a free point will be outlined to document tool success. The pipe cutting system performed successfully in all cases thus validating the objective of allowing multiple cuts in the casing and minimizing the number of trips required for casing cutting and recovery operation.