bluuebunny/crossref_metadata_2025 huggingface dataset:
Processing of Multi-Acquisition NMR Data
Authors: Slijkerman W. F. J. , Looyestijn W. J. , Hofstra P. , Hofman J. P.
Published: December 2007

Crucial issues in formation evaluation are the determination of porosity, permeability, hydrocarbon volumes and net-to-gross ratio. NMR logging provides measurements that are directly related to these parameters. The NMR response of fluids contained in pores is governed by their T2 and T1-relaxation times, diffusion coefficient and whether or not they wet the rock. In the case where fluids possess a sufficiently large contrast in these properties and NMR data has been acquired with suitably chosen acquisition parameters (i.e. wait times and/or interecho times) a separation of water, oil and gas NMR responses can be made. From these separate NMR responses the hydrocarbon volumes, porosity and permeability estimates are subsequently calculated. Key in these applications is the ability to include all the acquired log NMR data into the processing towards the desired end result.

Methods exists to derive hydrocarbon volumes from T2-distribution or from echo decay data. However, these are all methods in which the difference between just two acquisitions that only differ in either wait time or interecho time are considered. Over the past years we have developed, tested and employed an alternative processing technique named MacNMR (Multi-acquisition NMR). MacNMR takes any number of log acquisitions (wait time and/or interecho time variations) and simultaneously inverts them using an rigorous forward model to the desired water and hydrocarbon T2 spectra. In this paper we discuss the concepts of MacNMR and demonstrate its versatility in NMR log processing. An example will illustrate its benefits. MacNMR is implemented across Shell operating units worldwide and has been in use for over two years now.
Enhanced NMR Logging Methods for Accurately Measuring Volumes of Gas and Light Oil in Hydrocarbon Reservoirs
Authors: Hou B. L. , Coates G. R. , Galford J. E. , Miller D. L. , Reddy A. P. , Bouton J. C.
Published: December 2007

Using nuclear magnetic resonance (NMR) logging to determine reservoir porosity occupied by gas or light oil currently requires data simultaneously acquired from at least two Carr-Purcell-Meiboom-Gill (CPMG) sequences having different wait-times. This dual-wait-time and dual-frequency method has been successfully applied to determine gas volumes in both clean and shaley sand formations. The success of the method relies on two factors. First, adequate signal-to-noise levels in an echo train difference must be maintained so that the gas-filled porosity and its transverse relaxation time (T2) can be accurately characterized. Second, methods must be available to reliably estimate the longitudinal relaxation time (T1) of the hydrocarbon phase needed to apply a necessary amplitude correction to the apparent hydrocarbon-filled porosity.

A new triple-wait-time and multifrequency method has been developed for determining gas and light-oil-filled porosity over a broader range of reservoir conditions. When compared with the dual-wait-time, dual-frequency logging technique, the new method offers two advantages. First, it improves the signal-to-noise ratio of the echo train difference. Second, it significantly improves the determination of T1 values for the hydrocarbons, especially when the reservoir contains oil, gas, and water. The new method thus enables a more accurate determination of the pore volumes occupied by each hydrocarbon phase as well as the pore volume occupied by water.

Results from laboratory experiments, performed on bulk fluids and a sandstone core, are presented to demonstrate the new method. In addition, a set of charts is provided as an aid in the selection of optimum acquisition parameters for logging applications.
Control of Hydrogen Sulfide in Oil and Gas Wells With Nitrite Injection
Authors: Sturman P. J. , Goeres D. M. , Winters M. A.
Published: December 2007

The downhole injection of nitrite-containing solutions into sour oil and gas wells under controlled conditions has been observed to effectively remove hydrogen sulfide (H2S) from aqueous and gas phases. Souring control using nitrite has been successfully applied to a gas well in the San Juan Basin of New Mexico and to an oil well in the Amoco Netherlands Rijnfield. H2S removal from topsides water separations equipment was also facilitated using nitrite. Injected nitrite ((NO2−)) scavenges H2S and prevents the activity of sulfate-reducing bacteria while it is present. H2S production from oil or gas wells treated with nitrite may be suppressed for much longer periods of time. In a 36-hour downhole squeeze in a gas well, injected NO2− removed H2S from produced gas for a period of 7 months. SRB populations in produced fluids were reduced for a period of 3 months following treatment. In an oil dehydrator, the addition of NO2− during regular operation resulted in a decrease in aqueous-phase H2S from 40-60 mg/l to less than 1 mg/l. Corrosion rate data indicated a less corrosive environment during the NO2− addition period than prior to the addition. In a downhole squeeze in an oil production well, injected NO2− decreased H2S in associated gas from 140 ppm to less than 1 ppm for 60 days following treatment. H2S levels remained below pre-injection levels for 6 months following treatment. Oil production increased immediately following the treatment, probably due to the dissolution of precipitated iron sulfides in the zone surrounding the well bore. This treatment has proven an effective means of controlling H2S in oil and gas wells as well as a method of removing iron sulfide scale from the near wellbore.
Dipping-Effect Correction for the High-Definition Induction Logging Tool Using New Geometrical Factors
Authors: Fang Sheng , Wang Tsili , Geldmacher Ingo M.
Published: December 2007

A new algorithm for dipping-effect correction of the High-Definition Induction Logging (HDIL) data has been developed. The new algorithm is implemented based on the newly derived geometrical factors that generalize the Doll geometrical factor to the dipping beds. Processing of the synthetic data and real logging data verifies that this new algorithm works reasonably well for a wide range of dip angles (up to 75 degrees).
A Deterministic Method for Gas Reservoir Evaluation Using Dual Wait-Time NMR and Density Log Data
Authors: Them Holger F. , Chen Songhua
Published: December 2007

Accurate estimates of porosity and fluid saturations are critical for the proper evaluation of a gas reservoir. These properties are determined by combining data from a dual wait-time (DTW) nuclear magnetic resonance (NMR) log and a density log. The novel deterministic method additionally yields several in-situ gas properties.

The density and dual wait-time (DDTW) technique is applicable to reservoirs where the pore-filling fluid consists of one liquid phase and one gas phase. The low proton density of the gas phase causes a reduction in the NMR signal strength resulting in underestimation of the apparent porosity. The amount of polarization for different wait-times depends on the specific spin-lattice relaxation time of each fluid and may cause additional NMR porosity underestimation. The density log, however, delivers a porosity that is overestimated because of the presence of a gas phase. Published correlations for gas properties are used to establish the new deterministic method. DDTW primarily yields the total porosity ϕ, and the flushed zone gas saturation, Sg,xo. Other derived properties are the in-situ gas density, ρg, as well as the two NMR-related properties hydrogen index, HIg, and spin-lattice relaxation time, T1g. Two field examples illustrate the method and an error propagation study supports its stability.
Improved Oil-in-Place Determination in Very Shaly Sandstones in the San Jorge Basin Using Total-Porosity NMR Logs
Authors: Khatchikian Alberto , Solanet Fernando , Ollier Carlos , Gamin Héctor
Published: December 2007

NMR logs run in oil-bearing, shallow sandstones in the Las Heras area of the San Jorge basin indicate that many reservoirs are shalier and have a much lower effective porosity than generally assumed from cores or conventional log evaluation based on density logs. This would imply that oil-in-place determination based on cores or density logs is overestimated, leading to erroneous estimates of recovery factors.

Extensive coring in a well with very shaly sands proved that NMR porosity for T2 above 3 ms is effective porosity, as clay content from infrared spectroscopy (FT-IR) measurements matched shaliness derived from NMR's total and effective porosity. As expected, core porosity (which includes clay-bound water) closely matched NMR total porosity.
Comparison of Permeability from NMR and Production Analysis in Carbonate Reservoirs
Authors: Quintero L. , Boyd A. , Gyllensten A. , El-Wazeer F.
Published: December 2007

Several issues come to mind in the pursuit of log-derived permeability. Two of them, often referred to in recent publications, are the accuracy of the parameter and the representative of this permeability. Permeability from nuclear magnetic resonance (NMR) logs is often compared to core, wireline formation tester mobility, drillstem test and production data. The variation in vertical and lateral extent of these different measurements can give valuable insight into reservoir behavior. Average matrix permeability can be estimated from wireline NMR measurements while the other methods can more accurately evaluate the directional reservoir permeability as it varies with heterogeneities such as vugs, fractures, maximum horizontal stress and stylolites.

Determining matrix permeability in carbonates from NMR data has been considered more difficult than in typical sandstone reservoirs. Recent developments in NMR carbonate analysis have provided insight as to how the permeability estimation from NMR logs can be improved. A method will be presented that overcomes some of the limitations of using NMR permeability in carbonates and will be compared with conventional NMR permeability estimation, core, wireline formation tester and drillstem test analysis in three Middle East carbonate reservoirs.
Oriented Drilled Sidewall Cores for Natural Fracture Evaluation
Authors: Laubach S. E. , Doherty E.
Published: December 2007

A procedure to orient drilled sidewall cores and to evaluate large natural fractures using microfracture indicators was successfully tested in three gas wells in Silurian Medina Group, Appalachian basin. Microfractures from these cores document the strike of fractures that control production. By running well bore image logs after coring, sidewall core holes can be detected and core azimuth determined. The main challenge to orienting the 1-inch-diameter cores is determining "up" direction, because sedimentary facing indicators are rarely visible, and currently deployed sidewall coring devices do not mark (scribe) cores. To find core tops we used fracture surface marks induced on core ends during recovery and examined image logs. Success rate for this core-orientation procedure is remarkably high, in these examples close to 85 percent. This shows that cost-effective sidewall core orientation is feasible. Oriented core, along with useful indicator microfractures, is a practical source of information on the attributes of large fractures.
Integration of Core and Log Information To Improve the Representation of Small/Medium-Scale Heterogeneity
Authors: Coll C. , Jing X. D. , Muggeridge A. H.
Published: December 2007

Reservoir heterogeneities exist at several length scales. Reservoir properties will depend on the scale that we are analysing on the reservoir (from core to grid block). Facies are normally identified in cores and classified based on microscopic and small scale features such as lithology, grain size, texture, sedimentary structure, colour and fossil content. However, facies information is only available in a few cored wells or in wells with high vertical resolution logging. Conventional logging is usually available in all wells, but it only provides information at a medium scale. This information can be calibrated with geological facies to generate electrofacies (also called petrofacies),1 from which reservoir property distributions can be predicted using 3-D modelling techniques.

In this paper, core and log information is integrated to create a facies and electrofacies database. Small-scale geological facies are calibrated with logs and used to generate electrofacies by using statistical analysis. More detailed geological models are then generated using electrofacies data. The impact of using an electrofacies scehme over the traditional log-derived facies scheme during stochastic modelling of reservoir facies has been demonstrated. Modelling performance prediction using both methods is analysed for the different stochastic realisations. The use of electrofacies schemes has been proved to give more accurate prediction of reservoir heterogeneity.
Application Limits of Stainless Steels in the Petroleum Industry
Authors: Oberndorfer M. , Kaestenbauer M. , Thayer K.
Published: December 2007

Stainless steels have a great variety of potential applications in the petroleum industry, mainly as an alternative to carbon steel in corrosive environments. Within a number of media that can cause corrosion problems with these materials, only chloride solutions and hydrogen sulfide are of importance in oilfield service.

A reliable tool that permits the proper selection of stainless steels has yet been missing. In order to provide engineering diagrams for this purpose, pitting and stress corrosion cracking (SCC) tests were performed. Specimens were exposed to NaCl solutions containing from 3 to 100,000 ppm Cl− at temperatures from 40 to 200 °C. This test configuration was chosen to give a better representation of actual service conditions than accelerated standard test procedures do.

Tested materials were the austenitic stainless steel grades 321, 316Ti (API LC30-1812) and 254 SMO, and 22Cr duplex (austenitic-ferritic) steel (API LC65-2205). Based on an optical examination of the specimens, no-risk regions of chloride concentration vs. temperature have been identified. Subsequently, service temperature limits have been deduced for each tested material.

Thus, material failures by pitting and SCC can be prevented without overdesigning. The results of the testing series are applicable to all chloride environments without presence of H2S, as they have to be handled by primary production equipment, as well as transportation and gas processing facilities.
Stress-Dependent Permeability: Characterization and Modeling
Authors: Davies J. P. , Davies D. K.
Published: December 2007

During the production lifecycle of a reservoir, absolute permeability at any given location may change in response to an increase in the net effective stress and a concomitant decrease in the value of in-situ permeability. This paper focuses stress dependent permeability in unconsolidated, high porosity sand reservoirs (offshore turbidites) and consolidated reservoirs (tight gas sands). Specifically we address: i) fundamental controls on stress dependent permeability, as identified through analysis of core samples, ii) rock-based log modeling of stress dependent permeability in cored and non-cored wells, and iii) implications for production based on data from reservoir simulation. This work reveals a fundamental difference between the stress dependent permeability behavior of unconsolidated and consolidated sand reservoirs. In unconsolidated sand reservoirs, the greatest permeability reduction with stress occurs in the sands with the highest values of porosity and permeability. In cemented sandstone reservoirs, the opposite is the case: most of the reduction in permeability occurs in sandstones with the lowest values of porosity and permeability. This difference in behavior between unconsolidated and consolidated reservoir sands is controlled by pore geometry.

We present a practical, rapid and cost efficient methodology to improve evaluation and enhance the productivity and management of stress-dependent reservoirs. The method is based fundamentally on the identification of ΑRock Types≅ (intervals of rock with unique pore geometry). Thin section evaluation, together with integrated nuclear magnetic resonance and SEM-based image analysis of core material is used to quantitatively identify various Rock Types. Rock Type data is integrated with measurements of permeability at various levels of stress. Results demonstrate that, within a particular field, some Rock Types lose <10% of original permeability while others lose >90% of original permeability as a function of increasing stress. Rock Types are then identified using routine suites of wireline logs, allowing for field-wide determination of the net footage and distribution of each Rock Type in all wells and the foot-by-foot calculation of permeability at any value of net effective stress. Based on geological input, the reservoirs are divided into flow units (hydrodynamically continuous layers) and grid blocks for simulation.

Several cases are presented of a conceptual, single well model of an overpressured, tight gas sandstone reservoir that include stress dependent permeability. Results of simulation analyses for varying conditions of reservoir stress demonstrate the importance of stress dependent permeability in more accurate forecasting of reserves and predicting optimum well bore producing conditions.
Quantification of the Contribution of the Different Components Concerning Two-Phase Flow in Heterogeneous Porous Media
Authors: Berentsen C. W. J. , van Kruijsdijk C. P. J. W.
Published: December 2007

Two phase flow through heterogeneous porous media can be divided in ‘convective’ and ‘diffusive’ flow processes. The ‘convective’ part consists of the flow behaviour due to the large scale permeability field variations and an additional ‘two phase’ part generally captured in relative permeabilities. The ‘diffusive’ process is generally captured in the capillary pressure formulation. In this study we express the two phase flow behaviour as a convolution between the multidimensional single phase (tracer) flow behaviour with the one-dimensional two phase flow behaviour. For Piston like flow through a more dimensional heterogeneous medium, the velocity field remains constant during flooding and one can divide the flow field in constant ‘one-dimensional’ streamtubes, see Lenormand (1995). Under the assumption that the variation in streamtubes through the same field during two-phase flooding is negligible one can express the watercut profile of two phase flow in the watercut profile for Piston like flow convolved with the Buckley Leverett saturation profile.

In this study we compute the Piston like flow through three different permeability fields (one homogeneous field and two heterogeneous fields with an omni-directional correlation length of 0.5 respectively 0.95). We calculate 4 different two-phase flow behaviours by means of convolution and compare this to fully two dimensional flow simulations performed with an in house developed streamline simulator. We define a measure - based on the difference between Piston like and Buckley Leverett production - to quantify and characterise each different two-phase flow type. It appears that the convolved two phase flow behaviour shows a reasonable estimate of the fully two-phase flow behaviour, although the difference in the two dimensional total mobility distribution can affect the moment of breakthrough considerably. The defined production measure appears to show similar results for both the convolved and fully simulated two phase displacements. The benefit of the convolution method is that with only a single high resolution Piston like displacement numerous different two phase flow displacements can be estimated very cheaply.
Reservoir Heterogeneity Mapping Using an Automated Pattern Recognition Approach
Authors: Hassibi Mahnaz , Ershaghi Iraj
Published: December 2007

In reservoirs with complex structure, such as turbidite sequences, rock fabrics exhibit great variations both vertically (example-Bouma sequences) and in lateral direction. In such formations, patterns observed on lithological logs can show considerable differences. Constructing rational and meaningful correlation models consistent with all the lithological signatures can be an enormous task before conceptualization of data on a 3-D geologic model. The proposed method can serve as an important pre-processing step to minimize the requirements of the human expert input in the sub-marker detection for substantial number of well logs. The automated techniques of pattern classification enhance the characterization and identification of stratigraphic features of laminated type reservoirs. The approach proposed in this paper works on basic lithological logs and marker information. It comprises noise filtering and pattern recognition that lead to identification of reservoir compartments. This helps in delineation of the lateral continuity and discontinuity of reservoir sand and shale laminations.
Unified Model for Steady-State Foam Behavior at High and Low Foam Qualities
Authors: Alvarez J. M. , Rivas H. J. , Rossen W. R.
Published: December 2007

Foams are used routinely worldwide to divert acid in well-stimulation treatments and on a pilot basis to divert gas flow in improved-oil-recovery projects. The complexity of foam behavior and apparent contradictions between foam studies has bedeviled attempts to understand foams and design effective field treatments.

In 1992 Osterloh and Jante[1] identified two distinct foam-flow regimes: a high-quality (dry) regime in which steady-state pressure gradient is independent of gas flow rate, and a low-quality (wet) regime, in which pressure gradient is independent of liquid flow rate. New data for foam with a variety of porous media and surfactant formulations, over a range of flow rates, show this behavior to be general. In each regime foam behavior is dominated by a single mechanism: at high qualities by capillary pressure and coalescence, and at low qualities by bubble trapping and mobilization. A new, unified model based on these insights unites foam behavior in acid well stimulation and gas-diversion IOR and reconciles apparently contradictory data. This model correlates the effects of parameters like rock permeability and surfactant formulation on foam behavior in the two flow regimes and on the transition between the two regimes. A variety of laboratory data, including bubble sizes, support the model assumptions.

Implications of these results for design of foam processes for IOR and acid diversion are discussed. These insights can guide the selection of foam formulation and injection quality for foam applications.
Effect of Gas Enrichment above the MME on Oil Recovery in Enriched-Gas Floods
Authors: Johns R. T. , Sah P. , Subramanian S.
Published: December 2007

The interaction of phase behavior and flow, in the presence of dispersive mixing, is examined for 1-D four-component enriched-gas displacements. Numerical and analytical solutions demonstrate that oil recovery may be substantially increased by gas enrichment above the minimum enrichment for miscibility (MME). The level of increase is dependent on the level of dispersive mixing and the size and shape of the two-phase region.

A critical gas enrichment (CGE) above the MME is defined that separates the multi-contact miscibility region into two regions: MCM1, when the gas lies within the region of tie-line extensions, and MCM2, when the gas lies outside. For enrichments below the CGE (in MCM1), oil recovery can increase significantly with enrichment. Above the CGE (in MCM2), oil recovery is not as sensitive to enrichment for the cases studied. Displacements in the MCM1 region exhibit a combined condensing and vaporizing mechanism, whereas displacements in the MCM2 region are purely condensing.
Project of Increasing Oil Recovery from UAE Reservoirs Using Bacteria Flooding
Authors: Zekri Abdulrazag Y. , Almehaideb Reyadh A. , Chaalal Omar
Published: December 2007

Due to the recent decline in oil prices, most of the enhanced oil recovery (EOR) processes, and especially the ones typically recommended for light crude such as micelles, polymer, or miscible gas injection processes have become economically unattractive. The oil industry currently is in dire need of a reasonable cost process that can both technically and economically be successful. For this reason, a tremendous amount of research effort was directed at UAE University to investigate the possibility of using bacteria, which is a minor cost material, to improve the oil recovery in UAE oil reservoirs.

This project focused initially on the study of the interfacial tension (IFT) between crudes from four different UAE reservoirs (BH, UZ, St, and UAD) and a thermophilic bacteria solution. The bacteria were obtained from local water tanks. The system temperature was varied between 30°-100°C and salinity ranged from 0 to 100,000 ppm. Tertiary bacteria solution core flooding experiments were then performed using carbonate rocks at reservoir conditions without injection of nutrient with the bacteria during the core flooding experiments. A good amount of effort was directed, throughout the work, to characterize the bacteria used and identify the mechanism by which bacteria works to improve the oil recovery.

Results of these laboratory studies show an abrupt reduction in IFT at high salinity and high temperature (i.e. reservoir condition) for all studied systems except for the St crude, which was sulfur rich. The IFT decreased from 40 dynes/cm to 0.07 dynes/cm for most of the studied systems. Also, tertiary bacteria flooding at reservoir conditions, on average, resulted in an incremental oil recovery of 15 to 20 % of the pore volume.
Cryo-SEM and ESEM: New techniques to Investigate Phase Interactions within Reservoir Rocks
Authors: Robin M. , Combes R. , Rosenberg E.
Published: December 2007

Recent advances in scanning electron microscopy allow the observation of liquid samples, either under a frozen state in the case of Cryo-SEM (Cryo Scanning Electron Microscopy) or directly with ESEM (Environmental Scanning Electron Microscopy).

In the case of sandstones, cryo-SEM studies have pointed out the special affinity between kaolinite and oil after aging, and shown the importance of both amount and distribution of kaolinite on wettability behavior at the core scale. Good correlations were found between observations at the pore scale and wettability indices. Wettability alterations were shown to be very sensitive to thermodynamic conditions (pH, salinity, etc.).

It has also been used to study the impact of the spreading coefficient on oil recovery by gas injection. It has been experimentally shown that both wettability and spreading could affect gas injection efficiency by controlling the distribution of the three phases at the pore level. It proved to be efficient in other studies such as emulsion characterization or asphaltene deposition.

The main advantage of ESEM is to operate under reduced pressure and to allow the observation of liquid-containing samples without any special preparation. Combined with Energy Dispersive X-ray Spectroscopy (EDS), it also allows elemental analysis.

It has successfully been used to investigate the sensitivity of different clays to freshwater, to characterize oil base muds, to analyze formation damage mechanisms and to improve acid stimulation.

Dynamic experiments are also possible such as drying, freezing or even capillary flows.

ESEM allows wettability estimation by direct visualization of both oil and brine in their liquid state; it has confirmed the results obtained by Cryo-SEM and the correlation between fluid distribution with either pore structure (carbonate) or mineralogy (sandstone).
Defining Reservoir-Rock Properties, Deep-water Depositional Facies of the Qua Iboe member, Pliocene, Offshore Nigeria
Authors: Joiner S. D. , Kreisa R. D. , Bloch R. B. , Paul J. B.
Published: December 2007

Reservoir facies provide the critical interrelationships among (1) basic reservoir lithologies, (2) reservoir properties, and (3) wire-line log measurements. In addition, each reservoir facies is linked to its depositional environment, thus providing the basis for understanding its three-dimensional geometry and interconnection. A reservoir-facies classification has been designed for the deep-water deposits of the Pliocene Qua Iboe Member of the Agbada Formation as they occur in Mobil Producing Nigeria's (MPN) Joint Venture Acreage. The facies are based on lithology and registered to laboratory-measured reservoir properties. Grain-size characteristics such as size, sorting, and terrigenous mud content are the principal factors that control reservoir properties. All reservoir facies have been precisely quantified in terms of routine and special core analysis and their compatibility with completions fluids has been tested. Furthermore, quantitative wire-line log criteria have been developed, allowing recognition of the reservoir facies in uncored wells with considerable accuracy. Log and reservoir properties associated with the facies are tailored to burial depth for each field, and even different reservoirs within a single field. Using these standardized classification schemes for all MPN reservoirs allows for better communication among reservoir technologists and the transfer of insights gained from one field to other fields.
Exploring Mature Areas: The Role of Technology
Authors: Krol D. E. , Noual V. , van Maren P. J. T.
Published: December 2007

The UK North Sea is mature after 30 years of exploration. The application of new technology to continue the discovery and development of smaller reserve base fields is essential. Advances in 3D seismic acquisition have enabled improved subsurface imaging. Ocean Bottom Cable (OBC) seismic can improve imaging of fields overlain by gas chimneys. PreStack Time and Depth Migration have contributed to better definition of steeply dipping prospects underlying diapirs. Amplitude Variation with Offset (AVO) can reduce exploration risk in a proven play. Quantitative interpretation techniques (e.g. seismic inversion) can be used to image reservoir units in mature areas. High resolution geochemistry can also assist intra-reservoir characterisation. New drilling techniques (e.g. multilateral wells) can unlock fault blocks, layered reservoirs or small outstep accumulations. Extended reach drilling from platforms is also effective in mature areas. Long distance subsea tiebacks, for both high pressure/ high temperature and low energy fluids, can make the development of small and remote hydrocarbon accumulations feasible. The Shell Expro multi-discipline organisation has identified new practices for exploration/keeper well design and equipment procurement which reduce the time between field discovery and first production. Innovative engineering designs are unlocking small field development. New commercial practices are also required to facilitate application of technology in mature areas.
The Other Millennium Dome
Authors: Hodges Sean , Line Charles , Evans Bob
Published: December 2007

A large (> 300 km2) dome-shaped structure (Ben Nevis dome) lies beneath a thin basalt layer in the far north of the UK continental shelf. A large gravity and magnetic anomaly (known confusingly as Brendan's Dome) lies only 20 km to its north-west. Shell/BPA⁎ modelled these features using high-resolution gravity and magnetic datasets and concluded that, whereas the anomaly is generated by an igneous intrusion, the Ben Nevis dome is composed of sedimentary material. A 3D seismic survey was subsequently acquired over Ben Nevis, greatly improving imaging of the sub-basalt dome, and also showing fine details of the intra-basalt structure. After considering several models for the formation of the Ben Nevis dome, Shell/BPA's preferred model is that it was probably formed by localised inversion of a Cretacous graben-fill when the adjacent Brendan's Dome gabbroic pluton was intruded.
The Search for Mountains of Oil: Exploration Activity in the Atlantic Margin, West Of Shetland
Authors: Parr R. S. , Cowper D. , Mitchener B. C.
Published: December 2007

BP Amoco and Shell have been major participants in the exploration activity in the deep water, West of Shetland, U.K.C.S. which has led to two new oil fields producing less than 6 years after discovery. The discovery of Foinaven and Schiehallion, both named after Scottish mountains, not only involved detailed technical understanding of the seismic response and rock properties, but also commitment by the participants to the vision of opening a new basin.

This paper reviews the historical exploration effort West of Shetland (W.o.S.) and then focuses on BP's discovery of both the producing fields. It describes the critical role of integrating careful seismic processing/analysis with the rock and fluid properties to exploit the Direct Hydrocarbon Indicators (D.H.I.'s). These were applied to reduce exploration risk and build the drilling strategy.

The discoveries also fundamentally changed the oil industry's perception of the basin. This led to a large investment in new acreage, widespread 3-D seismic surveys and a flurry of deepwater drilling activity. However, to date, no commercial discoveries have been announced outwith the main Foinaven-Schiehallion fairway. This paper concludes with an overview of the type of future opportunities that may exist within the basin.
Digital Imaging for Subsea Operations: Innovative ROV Tooling and Image Analysis Combinations for Mooring Chain Assessments Yield Cost Savings and Operational Confidence for Offshore Operators
Authors: Hall Anthony D. , Lethbridge Gail M.
Published: December 2007

Welaptega Marine Limited with the support of Shell UK Exploration and Production Limited and Total Oil Marine UK has developed and commissioned a system for the in situ measurement of offshore mooring chains. The chain measurement system (CMS) is deployed by ROV and functions as an optical caliper. After a series of trials and operational programs the system has proven itself to be a cost-effective and powerful analytical addition to the IRM tool arsenal for floating installations. It provides operators with opportunities to track the wear of chain moorings overtime, and to use the information to both anticipate and thereby avoid the failure of mooring systems, and to optimise logistic and cost planning related to the replacement of offshore mooring chains.
FPSOs Lessons Learned
Authors: Knowles N. , Selwa J. R. , Bankes G. J.
Published: December 2007

FPSO Developments have become a popular choice for smaller fields around the world. However, the majority of developments have encountered significant problems with design/operation and/or project overruns. This paper, based on a study carried out by IGL Engineering Ltd., for the Offshore Safety Division of the UK Health & Safety Executive reports on the principal types of problems encountered, discusses the underlying causes and proposes appropriate remedial actions to prevent recurrence on future projects.
The Gullfaks Satellites: New Subsea Technology, Start Up and Operational Experience
Authors: Knudsen Tor Willgohs
Published: December 2007

Norway's Gullfaks South, Rimfaks and Gullveig fields have now been tied back to the Gullfaks A platform. Production began on 10 October 1998. Innovative technology has been adopted from subsea wellhead to platform. Developed faster and more cheaply than any comparable previous project in the North Sea, these satellites will make an important contribution to continued profitable operation of the main field.

A major goal for this Gullfaks satellites project (GFSAT), operated by Statoil, was to reduce the cost of subsea installations by 40 per cent compared with the group's earlier Statfjord satellites project. This objective has been met. All facilities have now been successfully installed, but not all the objectives for quality assurance of design and fabrication were met. This caused some problems for completion and production operations.

Further development is now under way in the Gullfaks area, covering gas reserves in Gullfaks South and Rimfaks for export to continental Europe. This GFSAT Phase 2 project, due to come on stream in October 2001, will use more or less the same subsea technology as Phase 1 but with some improvements. It again involves substantial modifications to the Gullfaks C and A platforms.
Dynamic Underbalanced Drilling Effects are Predicted by Design Model.
Authors: Rommetveit R. , Saevareid O. , Lage A. C. V. M. , Guarneri A. , Georges C. , Nakagawa E. , Bijleveld A.
Published: December 2007

A dynamic model for underbalanced drilling has been developed in a joint industry project. The model is of use for planning an operation, and especially evaluations of dynamic pressure and flow effects. Use of the model can help prevent excessive pressure transients during operations, which will have negative effects on well productivity.

Experiments have been performed in a vertical, extensively instrumented, test well. The experiments focused on dynamic operations; such as kick-off or unloading, changes in liquid and/or gas injection rates and pipe connections as well as "steady state" periods. The tests were performed with either "parasite string" gas injection, or drillstring gas injection.

Simulations with the dynamic model has been performed, using experimental quantities as input (geometries, liquids, rates etc.)

Results show that the model performs very well for "parasite string" gas injection. For drilling gas injection system, the model performs well for low and medium gas rates. For very high gas rates, there is still room for improvements.
Well Construction, Competency, and the Tay Bridge Disaster
Authors: Laing C. M.
Published: December 2007

This paper makes uncomfortable comparisons between the Tay Bridge Disaster and some of today's well construction projects. It relates lessons learned from that disaster to the UK Design and Construction Regulations for wells and explores the importance of competency. It argues for more open access to information related to accidents and dangerous occurrences and for more sophistication in personnel selection.
Radical Solutions Required: Completions Without Packers and Downhole Safety Valves Can Be Safe
Authors: Durham Craig J. , Paveley Craig A.
Published: December 2007

In most countries the legislation regarding the design and operation of oil and gas producing wells does not specifically prescribe production packers or downhole safety valves. When interpreting the legislation, Operators generally specify a requirement for double barriers in wells that can sustain natural flow. Production packers and downhole safety valves are used commonly in completions to satisfy this requirement. The resulting policies provide a standard for well barriers and define an operational envelope that ensures pressure integrity and environmental protection consistent with safe operating practice. Through detailed risk and hazard analysis it has been possible to demonstrate that the elimination of packers and downhole safety valves from completions can be tolerated while achieving substantial savings through reduced equipment, workover and intervention costs. This paper summarises some of the reasoning and methodology used to justify the elimination of packers and downhole safety valves from completions and encourages the wider use of risk-hazard analysis techniques to develop more radical completion solutions.
Experiences and Learning Points From the Use of Steerable Rotary Drilling Systems on Northern North Sea Platforms.
Authors: Poku Ernest K.
Published: December 2007

KCA Drilling is incentivised under their lead contractor relationship with Shell Northern Business Unit (NBU) to introduce such technology as can be economically justified to improve drilling performance. One of the ways this aim was achieved in 1997 was the investigation and introduction of alternative BHA technology. One technology that has been introduced is Steerable Rotary Drilling (SRD) which was undertaken in late 1997 to improve on the overall ROPs observed with bent subs and mud motors. This technology was perceived by Shell Well Engineering as becoming a high priority due to the increasingly complex wells being drilled in the NBU. The tools were used in the 8 ½" hole section through a combination of Cretaceous shales and Jurassic sandstone formations on two wells. There have been some successes and some important learning points from the initial campaign which involved the drilling of around 15,500 ft of 8 ½" hole with the new technology across two wells. Quantitative information on achieved ROPs, rotary speed requirements, doglegs achieved and the Mean Time Between Failure (MTBF) of the SRD tool are detailed in the text. This paper details the benefits of SRD technologies in low dayrate environments and the prospects of enhancing overall drilling performance thereby reducing the costs of marginal wells. The paper also details a consistent approach for selecting suitable well candidates for the application of rotary steering technology in comparison to oriented steering based on an equation that incorporates technical factors including ROP, rig dayrate and SRD tool economics. The paper also explains ongoing work to improve and enhance the SRD tools further for more demanding applications. It also details the effects the alternative BHA characteristics are having on other technologies in the oil industry e.g. PDC bit design and cementing.
The NeuRobot Project: Advances in Drilling Technology for the New Millenium
Authors: Harris T. W. R. , Vullinghs P. J. J.
Published: December 2007

Coiled Tubing Drilling, and wider reeled systems, is being established within the industry as a highly promising technology development. This has the potential to significantly cut well costs and add value to numerous hydrocarbon field development projects. To realise such benefits, Shell U.K. Exploration and Production (Shell Expro), operator in the U.K. sector of the North Sea for Shell, Esso and other co-venturers, are working on "The NeuRobot™ Project", which can produce an advanced subsea well field development system, made up of three main technology drives

Advanced well-bore construction technology comprised of expandable solid tubulars, which can be used to construct reeled monodiameter wells An intelligent reeled drilling system incorporating advanced geosteering technology Small, highly automated, dynamically positioned, reeled system drilling vessels.

The paper will review the past development, current status and future strategy of the NeuRobot™ Project, highlighting the benefits of the numerous individual technologies that define NeuRobot™.
Solving Sanding Problems using a Sand Production Management System. Case Histories
Authors: Webster Craig McK. , Tovar D Juan J.
Published: December 2007

In this paper three case studies are presented of a Sand Production Management System (SPMS™) used to successfully predict, evaluate, resolve and manage sand production problems. These cover drilling and production problems in Lake Maracaibo, a subsea development in the North Sea and a prediction and management in the Far East. As a primary feature, the SPMS™ integrates the geomechanical characteristics of a reservoir, its deliverability and equipment performance throughout the life of the field. The system is based on a geomechanical model that determines the in-situ rock properties and field stresses then predicts the changes that will occur during reservoir depletion. Critical issues addressed include optimum well deviation and orientation, borehole size effects, critical production conditions, time to abandonment and sand control measures. In each of the cases, both drilling and production performance were improved significantly while minimising or avoiding sanding problems.
Realizing True Value From Rotary Steerable Drilling Systems
Authors: Johnstone John A , Allan Derek
Published: December 2007

To date the main focus in the use of Rotary Closed Loop System (RCLS) drilling technology has been the cost savings associated with the increase in the gross rate of penetration that can be achieved. This ignores the other value drivers, for example, improved real-time reservoir navigation and optimal placement of the well bore in the reservoir. This paper will demonstrate and quantify the benefits that can be realized in the use of this technology. Furthermore, it will demonstrate the increased flexibility that exists in the directional planning and execution of the well.

Field data shows how drilling performance on complex 3-D well trajectories, including horizontal and extended reach wells can be improved, and how the effects of common well bore problems such as spiraling, ledging, cuttings bed build up and formation damage can be minimized. The examples given a) demonstrate the performance improvements achieved and b) show further benefits in the reduction of problems associated with running the completion string through the delivery of a competent and useable well bore. A financial analysis taken from an operator case study clearly demonstrates the potential return on investment in RCLS technology.

Innovative rotary closed loop drilling can be used to extend the life of a field, particularly in a mature asset within the constraints of existing infrastructure. It has significant potential to reduce the number of wells required with existing technology to efficiently exploit the reservoir, clearly demonstrating the value it can bring to the operator.
Cement Plugs: Stability and Failure by Buoyancy-Driven Mechanism
Authors: Crawshaw J. P. , Frigaard I.
Published: December 2007

Setting cement plugs off bottom is a well recognised problem in the industry. Different causes of failure have been identified over the years and many have been addressed by improving practices used in the field. A remaining problem is the instability of the lower interface between the cement and the fluid below, driven by the greater density of the cement. That is, once a cement plug has been injected into the wellbore it must resist the tendency to fall through the less dense drilling fluid below until the cement has set. The fluid properties which ensure stability have never been satisfactorily established and it is this gap which is addressed by the current work.

Theoretical and experiment results are presented in this paper which allow the estimation of the yield stresses required of the fluids to stabilise a cement plug under any conditions of hole size, inclination and density difference between the cement and the fluid underneath. The experimental work shows that the model is somewhat conservative and this is discussed in terms of the assumptions made in each case.
Drilling Mud Discharge Reduction in the Shearwater HP/HT Gas-Condensate Field
Authors: Darke K. E. , Browning G.
Published: December 2007

British Government legislation effectively prohibits the offshore disposal of oil contaminated cuttings. By the end of 2000 this will include cuttings contaminated by synthetic / pseudo-oil based muds. In high pressure and temperature environments such as Shearwater, temperature and wellbore stability constraints restrict the use of existing silicate water based muds to tophole sections. Total containment of cuttings is therefore required. The Ship and Skip program implemented on Shearwater has demonstrated that total cuttings containment is possible even during high speed drilling of larger hole (16") sections without incurring drilling downtime. The phased nature and sound planning of the program was key to operational safety and cost.
Partnership, to Improve Health and Safety
Authors: Spiller Roger , Buirds Bobby
Published: December 2007

The UK oil and gas sector is becoming mature at a time of reduced oil prices and higher costs. Cost reductions coinciding with an increase in serious injuries require a new approach to health and safety.

The traditional anti union focus of the industry is now changing giving the Trade Unions an opportunity of working in partnership with oil companies and contractors to maintain an efficient and profitable industry whilst securing high standards of safety and employment conditions. The inclusion of Trade Union Safety Representatives will benefit the improvements needed.