North Sea Wells Research Articles

Lower Paleozoic petroleum from southern Scandinavia: Implications to a Paleozoic petroleum system offshore southern Norway

Petroleum occurring in lower Paleozoic rocks is known to be present in southern Scandinavia, northern Poland, and the Baltic states. Oil has been produced from lower Paleozoic reservoirs in Sweden; northern Poland; and the Baltic countries Lithuania, Latvia, and the Russian exclave area of Kaliningrad. The sources for this petroleum are marine, organic-rich muds deposited in the Cambrian, Ordovician, and Silurian. This article concerns geochemical analysis of oils extracted from sandstones and carbonates from the Norwegian Oslo Graben rift and locations in Sweden and describes, in addition, insoluble bitumens collected from lower Paleozoic rocks in the Oslo Graben, locations in Sweden, and from upper Paleozoic rocks in a Norwegian North Sea well. The oils in this study have several geochemical characteristics shared with oils from the Baltic states and northern Poland, and the maturities of the oils are, in general, low. The occurrences of bitumen and migrated petroleum in the Oslo Graben lead us to believe that petroleum also has been generated and expelled in the related offshore Skagerrak Graben, indicating that a Paleozoic petroleum system operated in the Skagerrak Graben. This potential petroleum system has not suffered the degree of uplift, erosion, and destruction of reservoirs experienced by the onshore Oslo Graben, making preservation of any petroleum accumulations in the Skagerrak Graben more plausible. Although speculative, these considerations should interest anyone involved in petroleum exploration in the Skagerrak and the Norwegian-Danish Basin, not the least because of the proximity of Skagerrak and major energy markets in Europe.

Biogenic gas(?) in fluid inclusions from sandstones in contact with oil-mature coals

This study was initiated to investigate if coals on the Norwegian offshore continental shelf (NOCS) expel petroleum and in which form. The results revealed that equally isotopically light methane (C1) was released from fluid inclusions in sandstones and from adjacent coal (60.9 to 72.7). The analyzed samples were collected from cored northern North Sea and mid-Norwegian shelf wells in the depth interval 3924–5095 m (12,874–16,716 ft). The vitrinite reflectance (Ro) values of the coals range between 0.53 and 1.12%, with most values between 0.8 and 1.0%. Only minor C2+ fractions were released showing much heavier gas isotope signatures similar to values seen in our in-house NOCS gas isotope database for comparable depths. The similar light C1 isotope values released both from the coals and from the fluid inclusions in the adjacent sandstones suggest that the origin of the gas is the coal, and that no isotope fractionation occurs during release of the gas in nature. Traditional isotope interpretation schemes suggest the C1 to have a biogenic origin, whereas recently published data also show the possibility for an early mature thermogenic origin. The isotope values represent averages of the total gas released from all the individual disintegrated fluid inclusions in each sample. These did not form simultaneously, but during multiple events potentially covering several million years. The release of isotopically light C1 proves gas presence in the sandstone at the time of fluid-inclusion formation. We therefore speculate that significant volumes of isotopically light C1 have been expelled from the analyzed coals over time. The expelled isotopically light C1 may mix with mature thermogenically produced gas and skew the overall methane isotope values of gas accumulations toward lighter values, thus explaining the isotopically lighter-than-expected gas accumulations on the NOCS (e.g., Troll, Frigg, and Draugen fields).

Development of polygonal fault systems: a test of hypotheses

Polygonal networks of normal faults in layer-bound sequences of fine-grained mudstones have formed without regional tectonic extension. The two leading hypotheses concerning the generic mechanism responsible for their development are: (1) horizontal stresses are reduced by syneresis; (2) coefficients of residual friction are very low. To discriminate between these hypotheses, the ratios between the minimum horizontal and the vertical effective stresses have been estimated in four North Sea wells penetrating Oligocene and Miocene sequences that contain polygonal fault networks. The effective stress ratios are c . 0.8, consistent with very low coefficients of friction but not with syneresis.

Through-Bit Logging: Applications in Difficult North Sea Wells

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 92256, "Through-Bit Logging: Applications in Difficult Wells Offshore North Sea," by John Runia, SPE, Shell EPT-R; John Boyes, SPE, Precision Energy Services; and Robert Jan Lodder, Shell EPE, prepared for the 2005 SPE/IADC Drilling Conference, Amsterdam, 23-25 February. Through-bit logging (TBL) is a data-acquisition method that uses the drillstring and bit as a conduit into the wellbore. Two case studies demonstrate obtaining data in difficult and trouble-some well situations in the North Sea. Recent developments include a new type of side-entry subassembly for surface deployment as well as provide a fishing method in case the logging tools become stuck during TBL operations. Compatibility with rotary-steering and measurement-while-drilling (MWD) operations is under development. Introduction Data acquisition in oil and gas wells has evolved over the last century. Wireline logging is mature, and logging while drilling (LWD) is developing rapidly, giving the end user options to perform data acquisition during the drilling phase, in open hole after drilling, or subsequently in the cased hole. All options have advantages and dis-advantages, and a balance must be struck between cost, quality, risk, and timing of data acquisition. In the new system, the logging tools are conveyed through the drillstring and pass into the open hole through a specially designed bit, with formation-evaluation data acquired with either wireline or memory tools—in the latter case, while tripping drillpipe out of the well, thus improving rig efficiency. Acquiring Log Data Fig. 1 shows how the logging tools are lowered inside the drillstring, passing through the bit into the open hole. The TBL bit shown in Fig. 2 is a conventional polycrystalline-diamond-compact (PDC) -bit design modified with a removable central section leaving a 2½-in. passageway. During nor-mal drilling operations, the central section (insert) is latched into the bore of the bit. When required, the insert can be released outwardly with a running tool attached to the bottom of the logging string. The running tool releases the insert and carries it (locked to the logging string in a fail-safe manner) into the open hole below the bit. Bit performance is similar to that of the standard PDC designs because, as Fig. 3 shows, the outward form is identical to the original, and the internal latching mechanism does not interfere with basic bit functionality. There are two methods of running the tool. For simple once-off memory-logging applications, the intention is to pass the logging string through the bit, then log in memory mode back to surface while tripping pipe out of the hole. The more sophisticated two-way tool enables a retrievable/reversible-latching method. After logging, the logging tool can be pulled back through the bit (and back to surface), closing the bit for further drilling or additional logging. Currently, the tool is run as part of a check trip or wiper trip [removing any restrictive bottomhole-assembly (BHA) items, such as mud motors and LWD tools].

Field Validation of Transient Swab-Surge Response With Real-Time Downhole Pressure Data

Summary This paper describes the field validation results of the transient swab-surge model with real-time downhole annular pressure data. The maximum pressures encountered during tripping or reciprocation are indispensible for making appropriate well-completion decisions. The prediction of swab and surge pressures is of critical importance in wells in which the pressure must be maintained within narrow limits of the pore and fracture pressures. It also plays a major role in running casing, particularly with narrow annular clearances. For these critical cases, a fully dynamic model is required to better estimate the maximum pressures encountered. This paper presents actual surge-and-swab field data collected with downhole-drilling-data measuring tools during tripping and circulating operations. These data were obtained from Alaska and North Sea wells with a range of hole diameters and different base-fluid muds. The data were compared and interpreted with steady-state calculations as well as a dynamic surge model, which includes the effects of fluid inertia and compressibility, wellbore elasticity, pipe axial elasticity, and temperature-dependent fluid properties. The sampling rate was specifically increased to 2 seconds and, in some cases, 1 second. This prevents downhole data attenuations and captures the full waveforms more accurately. Different operations were included in the downhole-drilling-data measuring tool runs to cover swabbing, surging, reciprocation, and simultaneous pumping operations during tripping. Model predictions for downhole pressure behavior were in excellent agreement with the measured real-time downhole pressure data.

THE APPLICATION OF ELECTRON SPIN RESONANCE AS A GUIDE TO THE MATURATION AND TYPING OF ORGANIC MATTER IN THE NORTH SEA

In early electron spin resonance (ESR) analysis of North Sea wells, maturation of organic matter (OM) was expressed in terms of maximum palaeotemperature (MPT) based on North American calibrations that did not consider the influences of kerogen composition or overpressure. In the North Sea, the MPTs were anomalous in overpressured sequences and relative to other indices of OM maturation such as vitrinite reflectance, so the ESR method was abandoned there in geochemical studies. However, early empirical study of North Sea ESR data indicated that, in relation to functions that linked temperature and pore pressure, some ESR parameters were predictable without reference to MPTs.In order to re‐evaluate ESR parameters as indices of OM maturation, the physical factors (temperature and pressure) which affect OM maturation are related in the present paper to the ESR parameters “g” (spectral position) and Ng (spin density) at six well locations in the northern North Sea. A third ESR parameter, W (line width), is not an effective guide to maturation levels due to its complex relationship to the physical factors and kerogen types. However, cross‐plots of W versus “g” and Ng appear to be as effective as pyrolysis for kerogen typing. Levels of maturation investigated in the North Sea wells range through the equivalent vitrinite reflectance values of about 0.50–1.50%. The values of “g” and Ng have been differentiated for kerogen type, but undifferentiated values of “g” have also been studied.Regression analysis has shown that there are linear relationships between the ESR parameters “g” and Ng, and the physical factors present‐day temperature (To), “effective” temperature (Te), and differential pressure (Pd). Correlation coefficients for both “g” (undifferentiated and differentiated) and Ng (differentiated) relative to the physical factors are high; the highest values are for “g” and Ng relative to Te and Pd (r =−0.950 for “g” differentiated or undifferentiated, r = 0.944–0.976 for Ng differentiated, respectively). However, correlation coefficients were lower for “g” and Ng relative to To.More frequent high correlation coefficients and larger sample populations suggest that “g” (undifferentiated) is a more reliable index of OM maturation than Ng(differentiated). However, the estimation of levels of OM maturation is improved if both indices are used together.The ESR method appears to be effective both for estimating levels of OM maturation and for kerogen typing. It has a number of potential advantages over other geochemical methods: firstly, it is more sensitive for estimating OM maturation than most other methods; secondly, it can be used to analyze organic matter which is as old as Proterozoic; thirdly, it does not destroy the samples analyzed.

Variation of velocity with effective stress in chalk:null result from North Sea well data

Wireline log data and pore pressure measurements from eight wells have been analysed to investigate how velocity in the Chalk of the Central Graben, North Sea depends on porosity and vertical effective stress. The main conclusion is that velocity shows no detectable dependence on vertical effective stress when porosity and vertical effective stress are treated as independent variables. This result contrasts with the behaviour of shales, which exhibit a reduction in velocity on unloading. The significance is that velocity in the Chalk cannot be used to detect the presence of any overpressure caused by unloading. It is suggested that the absence of an observable velocity reduction in unloaded Chalk is due to cementation.

Biostratigraphy of Jurassic–Cretaceous boundary strata in the Terschelling Basin, The Netherlands

SUMMARY The Jurassic–Cretaceous boundary beds in the Scruff Greensand Formation from Dutch sector North Sea wells L06-2 (between 2245.36 m and 2262.76 m) and L06-3 (between 2028.90 m and 2037.80 m) have yielded both ammonite faunas and abundant marine and terrestrial palynomorphs. Ammonite endemism in Europe was intense at the Jurassic–Cretaceous boundary. This means that pan-European correlations of Jurassic–Cretaceous boundary beds based on macrofossils are problematical. The ammonite faunas of wells L06-2 and L06-3 provide the most extensive and complete marine macrofossil record so far across the Volgian–Ryazanian (Jurassic–Cretaceous) boundary in the Spilsby Province and the North Sea Basin. The Primitivus, Preplicomphalus, Lamplughi, Runctoni and Kochi Zones have been identified. In both wells, the occurrences of the dinoflagellate cyst Gochteodinia virgula mean that the successions are no older than latest mid-Volgian. The dinoflagellate cyst associations of L06-2 are indicative of the late Volgian/early Ryazanian. The range tops of Gochteodinia virgula and Amphorula expirata are revised as a result of correlations with the ammonite zonation. Dinoflagellate cyst floras in L06-3 are indicative of the latest Volgian–? earliest Ryazanian. In particular, the co-occurrence of Batioladinium? gochtii and Gochteodinia virgula at 2030.60 m in well L06-3, together with ammonite data, indicates that this horizon is of latest Volgian (Lamplughi Zone) age. Both wells contain reworked palynomorphs, including recycled older Late Jurassic dinoflagellate cysts. In addition, the palynological assemblages yield relatively diverse sporomorph associations. The sporomorph succession of both wells is used to establish an ammonite-calibrated sporomorph chronostratigraphy. Comparison with other studies suggests that the Jurassic/Cretaceous boundary occurs within the Cherty ‘Freshwater’ Beds of the Purbeck Limestone Group in Dorset, southern England, and within the Serpulite Member of Germany.

Technical article: Gardner's relations and AVO inversion

Seismic reflection data contain information about the nature and the composition of a medium (its lithology, fluid content, porosity and so on). The lithological and fluid properties of a medium cannot be inferred from P-wave data alone: information on the S-wave response is also required. Although S-wave data are rarely directly acquired, S-wave information can be extracted from the P-wave amplitude-variation-with-offset (AVO). One consequence of this is a spurious correlation between estimated P-wave and S-wave properties; another is that S-wave related estimates are very sensitive to noise (Cambois 2000). AVO inversion is commonly applied as a means of retrieving P-wave and S-wave properties from seismic data. The use of a constraint, such as a Gardner-type relation, is highly recommended because, by reducing the number of parameters, it stabilizes the inversion. But the constraint introduces biases into the estimated parameters. As our ultimate aim is quantitative (rather than only qualitative) characterization of fluidfilled reservoirs, we studied the quantitative effects of using a Gardner constraint on AVO inversion. This paper shows results from synthetic models based on log data from four (one per AVO class) North Sea wells. A real data example from the North Sea illustrates the application of these results.

The kinetics of carbonate scaling—application for the prediction of downhole carbonate scaling

Reliable prediction of calcium carbonate, CaCO 3, scaling for estimating scale production oilfield production wells and surface facilities requires both thermodynamic models to indicate the tendency for scaling from solution and kinetic models to predict the rate of scaling and thus the time required to cause blockage. The application of such models could contribute to field scale management and in the development of more effective treatments of carbonate scale during oilfield production. The performance of a kinetic model for calcium carbonate scaling rate based on the measurements of individual calcite crystal growth rates is tested against scale deposition in tube blocking experiments using synthetic formation brines under pressure and temperature levels. The profile of the scale formed on the internal surface of the tube during the experiments was measured and compared with the predicted results from the kinetic model. The application of the kinetic model to the prediction of carbonate scaling in a North Sea well has also been tested. The results from the model are in good agreement with the actual scale profile recorded in the tubing by a downhole multi-finger caliper (MFC) tool.

Production Logging in Horizontal Wells by Use of Ultrasonics

Summary This paper discusses technical and practical aspects on the future needs for monitoring of flow conditions in deviated and horizontal production and injection wells. A monitoring technique based on ultrasound has been developed. Examples of measurements in various North Sea wells are presented. The results are promising, and show the potentials of nonintrusive techniques for flow monitoring. It is expected that a combination of several sensor principles would facilitate the interpretation of downhole flow conditions.

A simple but powerful model for simulating elastic wave velocities in clastic Silicate rocks

Abstract We describe a practical velocity model for clastic silicate rocks developed from the Kuster and Toksöz, differential effective medium and Gassmann theories. The model divides the total pore space into two parts, one associated with sand grains and the other associated with clays (including bound water). The difference in pore geometry makes the clay fraction more compliant with increasing porosity than the sand fraction. The model accurately simulates the combined effect of lithology, porosity, clay content, water saturation and fluid type on laboratory and logging P- and S-wave velocities. Velocity dispersion is modelled by considering the relaxed and unrelaxed extremes of fluid flow. Of three possible schemes for predicting S-wave logs from other logs, prediction from the P-wave sonic and porosity logs is generally the most accurate; comparisons of blind test predictions and S-wave logs at two Norwegian North Sea wells demonstrate the accuracy and robustness of the method. The predictions were further improved once geological information was provided on the formations encountered in the well. Examples of application to the prediction of velocity dispersion and dry frame moduli, the detection of hydrocarbons from crossplotting the P-wave and S-wave sonic velocities, and sonic log editing confirm the flexibility, accuracy and reliability of the model. The model has proved invaluable in constructing accurate models of the seismic reflection response in the vicinity of wells.

Laboratory evaluation of a new, selective water control treatment and its implementation in a North Sea well

A new weak gel consisting of a non-ionic, high molecular weight polysaccharide and an organometallic activator was developed for harsh reservoir conditions. A first field application was performed on a candidate well in an oil field in the German North Sea tidelands in June 1992. The treatment had to be designed for the entire range of the perforated interval. The polymer solution was readily injectable and the activator was added to the last quarter of the injected volume. The treatment was considered successful as the initial increased water-cut could be maintained at a level of 65%, the overall production rate being comparable to that before treatment. However, the desired reduction in water production was not achieved, presumably because formation permeability was higher than estimated. A laboratory post-implementation evaluation was conducted to find out whether a possible further treatment with a stronger gel might be feasible. The results indicate that formulations yielding stronger gels would still be selective and easily injectable and would show a far greater water control potential.

High-Permeability Fracturing: The Evolution of a Technology

Abstract Since its introduction almost 50 years ago, hydraulic fracturing has been the prime engineering tool for improving well productivity, either bypassing near wellbore damage or actually stimulating performance. Historically (and in many instances erroneously) the emphasis for propped fracturing was on fracture penetration or length, culminating in massive treatments for tight gas sands using several million pounds of proppant with design 1/2 lengths in excess of 1500 feet (460 m). More recently, the importance of fracture conductivity has become appreciated. This has led to exciting "new" applications of propped fractures in better quality reservoirs as illustrated by North Sea wells, stimulations in Prudhoe Bay, and "frac-pack" operations in the Gulf of Mexico and Indonesia. While better understanding and new technologies are being used today, the actual application of fracturing to higher permeability formations is not new. During early development of fracturing, nearly all applications were for moderate to high permeability zones (since low permeability rock was of little interest at oil prices of $3/BBL). While tremendously successful at increasing PI, these early high permeability treatments were doing little more than bypassing damage. More recent development of improved, artificial proppant, cleaner fluid systems, and new technologies have changed this, making it possible to truly alter reservoir flow and stimulate production from moderate to high permeability reservoirs. The primary new tool in the engineers arsenal is the development of "tip screenout" fracturing. While higher permeability formations provide the "new" applications, the actual philosophy shift for fracturing occurred with the massive, tight gas stimulations. while outwardly a traditional, straight forward, application of fracturing to poor quality reservoirs, in actual fact these treatments represented the first engineering attempts to alter reservoir flow in the horizontal plane.

Pliocene - Middle Pleistocene biostratigraphy in the Central Danish North Sea wells E-1, P-1 and TWB-12

Six foraminiferal assemblage zones and 6 subzones have been identified in the boreholes TWB-12, P-1 and E-1. The zones cover the interval from the Pliocene to the Middle Pleistocene. In TWB-12 and E-1 the Pliocene /Pleistocene boundary is placed at the first common occurrence of the species Elphidium oregonense. This species was not found in P-1, and the boundary is here, tentatively, placed above the last local occurrence of Cibicides grossus. The palaeoecological variations indicated by the Pleistocene assemblages, suggest several oscillations both in water depth and in palaeotemperature. A cold, shallow water interval with Elphidium oregonense at the Pliocene/Pleistocene boundary is followed by a Early Pleistocene warm, deep water interval with a high content of the genera Stainforthia and Bulimina. These deposits are probably from the warm Tiglian stage. The succeeding Early Pleistocene fauna! assemblages indicate a cold, upwards shallowing environment, and in this interval the arctic species Elphidiella gorbunovi often has a short ranged occurrence. The fauna! assemblages of the overlying deposits are characterized by the species Elphidium ustulatum and Elphidium albiumbilicatum, and indicates nearshore/ deltaic conditions. This part of the sequence probably includes the Early /Middle Pleistocene boundary. The uppermost assemblages in the examined sequence indicate arctic, shallow water conditions. They are, probably, of Saalian age, and are referred to Middle Pleistocene.

Brief: Risk Analysis and Monte Carlo Simulation Applied to the Generation of Drilling AFE Estimates

Summary This paper presents a method for developing an authorization-for-expenditure (AFE) -generating model and illustrates the technique with a specific offshore field development case study. The model combines Monte Carlo simulation and statistical analysis of historical drilling data to generate more accurate, risked, AFE estimates. In addition to the general method, two examples of making AFE time estimates for North Sea wells with the presented techniques are given.

High Resolution Nannoplankton Biostratigraphy: ABSTRACT

Abstract Non-conventional biostratigraphic techniques were successfully used in steering and maintaining two horizontally drilled North Sea wells (H{A}, H{B}) in a restricted target zone (upper third of the reservoir unit). The techniques were initially applied to well A (well nearest site of first horizontal well). Verification of these techniques in both the first horizontal well (HA), and well B (well nearest site of second horizontal well) eliminated the need for drilling, coring, and logging a pilot hole in the HB (second horizontal well). This resulted in a significant savings to Phillips. These techniques, which provide high resolution nannoplankton zones with finer resolution than the conventional NN/NP or CN/CP zones, were used to subdivide the major Tertiary reservoir unit (reworked Cretaceous Zone, Field Layer ED) of the Ekofisk Field into three units. These techniques include: (a.) population dynamics, (b.) polar ordination, (c.) morphometric analyses, and (d.) synchronous variation of nannofossil assemblages and petrophysical parameters. 1. The middle unit of the reworked Cretaceous zone was defined by a marked increase in the abundance of Lucianorhabdus cayeuxii plus the influx of reworked Campanian taxa. 2. Polar ordination of the nannoplankton assemblages through layer ED verified the three subzones, plus the possibility of a fourth. 3. Morphometric measurements of the reworked Cretaceous taxa Arkhangelskiella cymbiformis reflected the same three subdivisions. 4. Two spikes in Thoracosphere-Calcisphere abundance, which can be used as a proxy for silica abundance, flag two porosity-permeability partitions in the reservoir. These partitions occur at, or near, the subzone boundaries. The technology, techniques and zonal scheme, was transferred to the Stavanger office and was subsequently used, on wellsite, by paleontologic consultants during the drilling of both horizontal wells.

Monobore Completions for Slim-Hole Wells

A growing number of operators are looking at monobore and slimhole completion techniques as possible solutions to economic and operational problems. Each technique can enhance the completion, and because the advantages of each concept affect a different phase of well technology, a broad spectrum of operational advantages could be generated is these techniques were merged into a single completion approach. Each philosophy, however, requires specialized equipment to provide its benefits, and attempts to unite the two strategies have created unique challenges for equipment designers. In many cases, these challenges are not really fully understood. This paper overviews several new equipment designs that are ideally suited for monobore completions in slim-hole wells. Also discussed are new servicing methods and how using these options and the newly designed equipment can overcome the difficulties challenging the design of completion equipment for the combined technologies.

Significance of K-Ar ages of authigenic illitic clay minerals in sandstones and shales from the North Sea

AbstractPetrographic, X-ray diffraction, and microprobe analyses have been used to assess the significance of illite K-Ar ages from sandstones of two North Sea wells. Three closely spaced samples in one well from the upper Statfjord Formation yield similar ages (69-79 Ma) although the illites formed from different precursor minerals. Pore-filling illite in the upper Brent and the Upper Skagerrak Formations from a second well formed by replacing groundmass clays and other detrital minerals. The average layer charge and K+ content increase slightly with depth (0.69-0.80 K+) due to minor reaction and crystal growth during burial diagenesis. These K-Ar ages increase from 15 to 33 Ma within a 500 m depth interval. The K-Ar age vs. depth relationship for these samples corresponds to the burial rate during the middle Tertiary. In examples of extensive illitization of pore-filling clays in sandstones with little subsequent evolution of the clay minerals, the K-Ar ages indicate the age of diagenetic events.In contrast, illitic minerals in shales from the Skagerrak Formation in the second well yield an age (108 Ma) that is much older than the clays in the sandstones, but is still younger than stratigraphic age. The K-Ar ages from illitic clay in shales reported in the literature can get younger, older, or remain essentially unchanged with increasing depth. These age vs. depth trends reflect the complex interplay of crystal growth and dissolution during diagenesis, as well as probable contamination by non-recrystallized detrital illites. The K-Ar ages of illitic clays, therefore, evolve in a different manner in shales than in sandstones.

Shale-fluid interaction under simulated downhole conditions, and its effect on borehole stability

Shales are often the most troublesome of all formations to handle when drilling for oil and gas. in this work, Seal-peal shale samples from three North Sea wells have been tested. This paper will report the results from one of these wells.