Nederlandse Aardolie Maatschappij Research Articles

What did NAM do to get a social licence to operate? The social impact history of the Schoonebeek oilfield in the Netherlands

From 1943 to 1996, the small rural community of Schoonebeek in the eastern Netherlands hosted the largest onshore oilfield in western Europe. Some 250 million barrels of oil were produced, bringing prosperity to the municipality and local community. With generous compensation paid by NAM (Nederlandse Aardolie Maatschappij, a partnership between Shell and ExxonMobil), local people greatly benefited from oil extraction. However, there were also negative social impacts, including: an influx of outsiders; changes to social structure, social fabric, social cohesion, and community identity; disruption to the peaceful rural setting; and industrialisation of the landscape. Nevertheless, the oil pumping installations (‘jaknikkers’ or nodding donkeys) ultimately became positive symbols of local place identity. Despite the negative social impacts, oil production came to be viewed positively by most local people, and a high level of trust developed between the host community and NAM because of the social performance strategies that were implemented: NAM employed many local people; minimised physical displacement; provided generous compensation for economic displacement; respected the social, cultural and religious wishes of the host community; and quickly addressed any social or environmental issues that developed. These actions meant that NAM gained a strong social licence to operate and grow.

How Upstream can play a role in energy transition

In the Netherlands, Nederlandse Aardolie Maatschappij has begun projects for reducing emissions and investigating new lines of business involving carbon dioxide.

Saturation Modeling Under a Complex Fluid-Fill History: Drainage and Imbibition

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 188594, “Saturation Modeling Under Complex Fluid-Fill History—Drainage and Imbibition,” by H. Xian, SPE, L. Beugelsdijk, SPE, and A. Kohli, SPE, Shell; E. Fokkema, SPE, Nederlandse Aardolie Maatschappij; and A. Cense, Shell, prepared for the 2017 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 13–16 November. The paper has not been peer reviewed. This paper presents a saturation-modeling approach for fields and reservoirs with complex hydrocarbon-charging histories. The model resolves saturation-height functions for the primary-drainage, imbibition, and secondary-drainage equilibriums. As part of the approach, a method of evaluating the residual-hydrocarbon saturation below the initial free-water level (FWL) is proposed. The developed theory is based on the principle of capillary-pressure/saturation hysteresis on the drainage/imbibition process in a water-wet system. Introduction Many discovered oil and gas fields are found to have gone through complex fluid-fill histories where residual hydrocarbons are observed below the FWL. To add to the complexity, some of these are giant fields and are divided into compartments with varying contacts and FWLs. To model saturation-height dependencies for reservoirs in fields under imbibition equilibrium, one of the adopted practices is to use a drainage model built from core data or log data to compute the saturation starting from the original FWL contact but only calculate the hydrocarbon-in-place volumes above the initial FWL. Another common practice is to build log-based drainage models using the current FWL while ignoring the uncertainties in the transition zone from the imbibition effect. These approaches typically lead to an inappropriate estimation of the hydrocarbon saturation in the transition zone and normally require separate models for different segments of the field. In this paper, an approach is presented for modeling the core capillary-pressure imbibition and secondary drainage cycles, integrating with log-based saturation-height models, and designing a work flow for upscaling and implementation in 3D reservoir models. Imbibition and Secondary-Drainage-Model Theory Hysteresis of Saturation/Capillary Pressure and Analytical Imbibition Model Method. Modeling of saturation/capillary pressure of primary-drainage-imbibition hysteresis is more complicated than other types of hysteresis effects because its cycle is not a closed loop; the imbibition route does not end at the starting point of the primary drainage route. Fig. 1 shows the multi cycle drainage/imbibition scanning curves in mixed-wet or strongly water-wet rock systems. Saturation changes caused by the imbibition-hysteresis effect are larger at lower capillary pressures in the transition zone but become insignificant over the higher capillary pressures across the main nonwetting-phase column. The primary-drainage capillary pressure can be measured by high-pressure mercury injection, porous plate, and centrifuge. Spontaneous imbibition can be measured only by use of the porous-plate technique or by use of an Amott cell. The forced imbibition part of the imbibition capillary pressure can be measured by porous plate and centrifuge.

Integrating Managed-Pressure Drilling Into HP/HT-Well Planning

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 188335, “Integrating Managed-Pressure Drilling Into HP/HT-Well Planning,” by Michael Cadd, Lewis Steven, and Robert Graham, Shell; Fedderik van der Bos, Nederlandse Aardolie Maatschappij; Craig Leggett, Blade Energy Partners; and Emil Stoian, Weatherford, prepared for the 2017 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 13–16 November. The paper has not been peer reviewed. Managed-pressure drilling (MPD) is an increasingly common technique in narrow-margin high-pressure/high-temperature (HP/HT) wells. However, MPD is sometimes viewed as a bolt-on technology, only added after much of the planning work has been carried out and all other alternatives have been exhausted. The decision to use MPD should be made at the earliest stage of well planning. An early commitment to integrate MPD into an HP/HT drilling operation can make MPD more than just an enabling tool and turn it into a performance tool that offers significant operational benefits. Overview Project 1. For an HP/HT field redevelopment in the UK North Sea, seven side-track wells were drilled from a jack-up over an existing platform. MPD was used from the beginning, but the full benefits of MPD were not realized until later in the project. MPD was initially included to hold surface backpressure (SBP) across two connections to mitigate borehole-stability risk in an un stable shale. However, once the system was operational, further benefits continued to be identified and the scope of MPD operations grew significantly. At the same time, more knowledge of the subsurface was being gained, and it became clear that some of the planned wells would not be drillable without MPD because of a significantly reduced drilling window in the overburden. MPD became a key part of the design philosophy for later wells, where managed-pressure techniques were used to set and cement casings significantly deeper than would have been possible conventionally. MPD successfully mitigated classical HP/HT issues so that problems with losses and gains, handling of elevated gas levels, and mud-weight-selection issues were all virtually eliminated. Project 2. For a standalone HP/HT exploration well drilled from a jack-up offshore the Netherlands, MPD was initially selected because of the extremely narrow margins between the pore and fracture pressures in the 8½- and 6-in. sections. Conventional drilling would not have been possible without inducing losses and spending significant time circulating to adjust mud weights, as seen in a key offset well. Taking advantage of the learnings from Project 1, MPD was selected at an early stage of the planning process and was fully integrated into the well design and operations. Mud weight, drilling parameters, and bottomhole-assembly design were all tailored to suit MPD operations. Integrated HP/HT and MPD procedures were developed on the basis of traditional HP/HT techniques but were modified to make full use of the additional functionality provided by MPD. A combined HP/HT and MPD training course was developed, and key personnel were trained in HP/HT and MPD techniques. Rig modifications were made well in advance, and MPD was implemented one hole section earlier than required to familiarize all crews with the new equipment and procedures. The result was a potentially extremely challenging well that was drilled without any of the conventional HP/HT problems observed in the offset wells.

Unlocking 4D seismic technology to maximize recovery from the pre-salt Rotliegend gas fields of the Southern North Sea

AbstractThe Southern North Sea is a mature gas basin, producing mainly from faulted Permian Rotliegend sandstones. Identifying infill well opportunities in un-depleted or partially depleted blocks in these fields is challenging, particularly if the sealing capacity of faults within a field is uncertain. Time-lapse (4D) seismic monitoring provides an opportunity to identify depleted reservoir blocks by measuring differences in travel time across the producing interval between seismic surveys acquired before and after gas production. 4D seismic field tests were initially performed by Nederlandse Aardolie Maatschappij (NAM) and Shell in 2001. However, the observed travel-time differences proved to be smaller than predicted and any possible signals were too noisy to confidently detect depletion. Since then, advances in seismic acquisition and processing technology have improved the accuracy of 4D measurements and enabled the effective mapping of 4D related gas depletion signals. 4D seismic has now been deployed over a number of fields in the Southern North Sea, and a portfolio of infill opportunities has been identified. In 2015, the first 4D targeted infill well was successfully drilled into a block with limited depletion. This technology represents a breakthrough for operators seeking to maximize hydrocarbon recovery and extend field life in the Rotliegend play of the Southern North Sea.

Comment on “The Maximum Possible and the Maximum Expected Earthquake Magnitude for Production‐Induced Earthquakes at the Gas Field in Groningen, The Netherlands” by Gert Zöller and Matthias Holschneider

Zoller and Holschneider (2016) propose estimates of the maximum magnitude of induced earthquakes resulting from gas production in the Groningen field in The Netherlands by applying the approach of Zoller and Holschneider (2014) to the earthquake catalog for the Groningen field. We wish neither to make any comment on the analytical approach that the authors propose, nor to comment on their results in this particular application. We do feel obliged to clarify for readers the context of the study by Zoller and Holschneider (2016) in relation to the March 2016 workshop to which they refer. In particular, the sentence in their Introduction stating that “this short note provides the results of those authors” (p. 2917) could be interpreted as implying that their paper presents the results from the workshop. The paper by Zoller and Holschneider (2016) summarizes one of the many inputs that contributed to the workshop, but not the final outcome of the workshop. In response to induced earthquakes in the Groningen gas field, the field operator Nederlandse Aardolie Maatschappij (NAM) is leading an extensive data acquisition and modeling effort to quantify the consequent seismic hazard and risk as a basis for decision making regarding appropriate mitigation measures. All the elements of the study are subject to peer review and the results presented in the open literature (e.g., Bourne et al. , 2014, 2015; Bommer et al. , 2016). Originally, the maximum magnitude M max for the probabilistic seismic‐hazard analysis (PSHA) conducted for the gas field was set at M 6.5, a value obtained from the seismic moment corresponding to the strain energy associated with the entire field compaction at the end of production life being released in a single seismic event (Bourne et al. , 2015). Although the observed strain partitioning factors (i.e., the portion of the total strain that …

Technology Focus: Mature Fields and Well Revitalization (January 2014)

Technology Focus Sustainable growth in oil and gas production must stem from a combination of new discoveries and optimized recovery from maturing fields. Therefore, development of mature oil fields has been, and will increasingly be, an attractive subject. Consequently, there is a large number of published studies describing the methodology of mature-field-development practices. However, it is also evident that optimizing the production of mature fields presents great technological challenges for the operators, who must manage production decline over the short term while increasing recovery factors over the long term. There are opportunities for quick wins, but, for long-term growth, a coherent strategy that integrates elements of technology, people, and process must be established. A significant amount of information is available that covers almost all aspects of managing mature fields. It is critical to have access to the relevant information and to use the right tools to improve decision cycle time. This allows the operators to correct course in a timely manner and to avoid implementing changes in a compartmentalized fashion. It is straightforward to establish processes and follow best practices, but having people with multidisciplinary expertise is the glue that holds all the pieces together. Many in the industry have stressed the importance of properly developing experience and capacity for innovation. However, promoting the culture of innovation requires patience, which is challenging for public companies that are under quarterly pressure. It is exciting to see that there is no shortage of technological advances, but it is safe to say that there is still plenty of room for key enablers to continue to evolve and to synergize with each other. For instance, chemistry, as a basic science, could play a bigger role in the overall scheme and perhaps, in certain areas, should take the leading role. Nature has designed countless examples of well-choreographed chemical reactions that support the complexity of life. It is conceivable that such intelligent chemistry can also be developed to broaden the role of chemistry in terms of managing mature fields. I hope to see more and more chemistry-related publications in the coming years. The decline of a field’s production curve is inevitable; good preparation helps to control the process. I remember reading this statement from one of the majors: “Preparations for field maturity must start with first oil.” In parallel, one must also keep in mind that social responsibility, especially the environmental aspect, should be one of the key considerations while establishing the development strategy. Again, this is where chemistry can bring significant value. For instance, precise fracturing technology that uses less proppant is a good example of new technology that exhibits uncompromised performance that is one step in the right direction. I hope you enjoy reading the selected papers for this month’s feature. JPT Recommended additional reading at OnePetro: www.onepetro.org. OTC 24092 A Mature Southern North Sea Asset Considers Conversion to Wet-Gas Operation, Which Requires the Development of Compatible and Novel Chemistries for Flow Assurance and Asset Integrity by J.F.L. Garming, Nederlandse Aardolie Maatschappij, et al. SPE 166300 Reducing Brownfield Development Costs Through Improved Drilling Practice and Enhanced Understanding of Wellbore Instability in Weak Formations by N. Stevenson, Statoil, et al. SPE 160429 Innovative Solution Successfully Recompletes Problematic Well in Malaysia by Chris Elliott, Petronas Carigali, et al.

The discovery of the Fat Sand Play (Solling Formation, Triassic), Northern Dutch offshore – a case of serendipity

AbstractIn 1992, the well L9-7, drilled by the Nederlandse Aardolie Maatschappij (NAM) unexpectedly found a thick previously unknown sandstone interval with excellent reservoir characteristics in the Middle Buntsandstein (Triassic) of the Dutch Northern Offshore: the ‘Fat Sand’. A follow-up well, L9-8, found this reservoir gas-bearing in an accumulation that turned out have recoverable reserves of circa 1 Tcf of gas distributed over several fault compartments. This serendipitous discovery led to a frantic period in NAM's office trying to understand the setting of this local sand development and, most importantly, assess follow-up potential; could this sand be present elsewhere in a trapping configuration? The local depocentre in which the Fat Sand accumulated is considered to be caused by local extension along a strongly listric fault soling out on the top of the Zechstein Salt. This supra-salt fault seems to be caused by early east-west extension in the Dutch northern offshore. The shape of the fault plane was strongly influenced by the presence of the nearby Zechstein Salt, and by early salt flow, which was also triggered by E-W extension.

Schoonebeek Heavy-Oil Redevelopment Requires Complex Chemistry Management

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 150635, ’Integrated Production Chemistry Management of the Schoonebeek Heavy Oil Redevelopment in the Netherlands: From Project to Startup and Steady State Production,’ by Andrew G. Shepherd, SPE, Stuart Mcgregor, and Ruud Trompert, Nederlandse Aardolie Maatschappij, and Sen Ubbels, Bob van de Gender, SPE, Theo van Ommen, SPE, and Sjoerd van der Knoop, SPE, Champion Technologies. The production chemistry management process undertaken during the design, commissioning, and startup of the Schoonebeek redevelopment faced challenging separation issues, saline water, and a multitude of other process conditions that resulted in a complex application portfolio. Chemical selection was conducted in adherence to health, safety, security, and environment (HSSE) directives and focused on unique produced fluid properties. Since startup, the success of chemical performance has come from the availability of chemical treatment programs and surveillance/sampling plans. So far, no contingency chemicals have been needed at the facilities. Introduction The Schoonebeek oil field was discovered in 1943 and operated until the late 1990s. A number of enhanced oil recovery methods were used in this field, including high- and low-pressure steam-floods, hot waterfloods, and in-situ combustion. The field is now being redeveloped, using low-pressure steam-flood with horizontal wells. Superheated steam, supplied by a combined heat and power (CHP) plant, will be injected into the reservoir through 25 wells adjacent to the production wells in 17 locations. Gross production will be evacuated from the reservoir through 44 horizontal wells in 18 locations using artificial lift pumps, with a casing vapor recovery (CVR) system included to improve the gross lifting capability. Production from each wellsite will be routed through a gross gathering system to the central treating facilities (CTF). The CTF will include the required facilities to separate the oil, water, and associated gas and treat the respective streams to export quality. Production Chemistry Management Compliance toward European chemical regulations (REACH) was one of main drivers for the short-listing of products to be applied in the Schoonebeek redevelopment. Schoonebeek crude oil has a relatively high API weight. Nevertheless, the crude oil is quite acidic, as seen in high total acid number and naphthenic acid values. Most (>90 wt%) of the naphthenic acids are in salt form, which means that they may affect oil/water separation. The crude oil also has very particular wax properties. A high cloud point and pour point indicate that wax precipitation and gelling in the facilities may become a problem during normal operations if not controlled. Furthermore, wax particles contribute to crude oil viscosity and also may affect separation. Fig. 1 presents an overview of the main chemical applications selected for treatment between the wellsites and the CTF and at the CTF itself, together with the main process vessels and streams.

Contemporary Approach Coupled With Traditional Techniques Tackles Extreme Wellbore Environment in Schoonebeek Heavy Oil Field

Summary The Schoonebeek heavy-oil field was first developed by Nederlandse Aardolie Maatschappij B.V. (NAM) in the late 1940s. Because of economics, it was abandoned in 1996. In 2008, the Schoonebeek Redevelopment Project, using a gravity-assisted-steamflood (GASF) design concept, was initiated with 73 wells (44 producers, 25 injectors, and 4 observation wells). Steam injection and cool-down cycles subject a cement sheath to some of the most severe load conditions in the industry. Wellbore thermal modeling predicted that surface and production sections would experience temperatures in excess of 285°C (545°F) and considerable stress across weak formations. A key design requirement was long-term integrity of the cement sheath over an expected 25- to 30-year field life span. Complicating this requirement was the need for lightweight cementing systems, because lost-circulation issues were expected in both hole sections, particularly in the mechanically weak Bentheim sandstone. The long-term integrity challenge was divided into chemical and mechanical elements. Prior research on high-temperature cement performance by the operator provided necessary guidance for this project. Laboratory mechanical and analytical tests were conducted to confirm the high-temperature stability of the chosen design. In addition to using lightweight components, foaming the slurry allowed the density, mechanical, and economic targets to be met. A standardized logistical plan was put in place to allow use of the same base blend for the entire well, adjusted as needed, using liquid additives, and applying the foaming process when necessary. This single-blend approach greatly simplified bulk-handling logistics, allowing use of dedicated bulk-handling equipment. The first well was constructed in January 2009; all 73 wells have been successfully cemented to surface. The steaming process, initiated in May 2011, has progressed with no well integrity issues to date.

Extreme-Environment Cementing in the Schoonebeek Heavy-Oil Field

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 150022, ’Contemporary Approach Coupled With Traditional Techniques Tackles Extreme Wellbore Environment in Schoonebeek Heavy-Oil Field,’ by Andrew Foster, Auke Pollema, Ian Petitt, SPE, and James Heathman, SPE, Shell, and Carl Johnson, SPE, and Rudy Schlepers, Schlumberger, prepared for the 2011 SPE Heavy Oil Conference and Exhibition, Kuwait City, Kuwait, 12-14 December. The paper has not been peer reviewed. The Schoonebeek heavy-oil field was first developed by Nederlandse Aardolie Maatschappij B.V. in the late 1940s. Because of economics, it was abandoned in 1996. In 2008, the Schoonebeek Redevelopment Project, using a gravity-assisted-steamflood (GASF) design concept, was initiated with 73 wells (44 producers, 25 injectors, and four observation wells). A key design requirement was long-term integrity of the cement sheath over an expected 25- to 30-year field life span. Complicating this requirement was the need for systems to place lightweight cement because lost-circulation issues were expected in both hole sections, particularly in the mechanically weak Bentheim sandstone. Introduction The Schoonebeek field was discovered in 1943 and was on production until 1996. During this period, 597 vertical and deviated wells were drilled. In 1995, two horizontal wells were drilled to test borehole stability while drilling horizontals and test sand production during the production phase. Core data in numerous vertical wells show that the reservoir is coarsening upward. The lower part of the reservoir has a lower permeability than the upper part of the reservoir. One-fourth of the original oil volume was produced over the approximately 50-year period (more than 250 million bbl). Approximately 120 million bbl is expected to be produced by use of the GASF technique. Planned plateau production is 3000 m3/d, with a steam-injection plateau of 8000 to 10 000 m3/d. Cementing thermal wells, particularly cyclic-steam-injection wells, is one of the most crucial and challenging cementing operations. Maintaining well integrity and zonal isolation over time is critical to the economic success of a steam project. The fundamental purpose of primary-cementing operations is the provision of effective zonal isolation during the life of the well. As wells become more challenging, more demands are placed on the cement-slurry design, operational practices, and in-situ properties of the well annular sealant. Uniform competent cement sheaths can minimize buckling, collapse, parting, or elongation caused by thermal stress.

The feasibility of effective and safe carbon dioxide storage in the De Lier gas field

The Nederlandse Aardolie Maatschappij (NAM) is looking into the feasibility of a CO2 injection and storage demonstration project near the Shell refineries in the Port of Rotterdam. As a first storage option the abandoned De Lier gas reservoir was identified and an extensive feasibility study concerning this specific site was conducted. This investigation was performed by teams from both the operator and the research institute. The main objective of the study was to assess the safe and effective containment of CO2 to be injected in the Holland Greensand gas reservoir in the De Lier field.

The concession Groningen: A lawyer’s view

AbstractThe discovery in 1959 of natural gas in a well drilled by the Nederlandse Aardolie Maatschappij (NAM) near Hoogezand, Gemeente Slochteren, a town in the Province of Groningen, led to the development and establishment of major natural gas production in the Netherlands. This important industrial development could not have started and the necessary investments would not have been made by the industry, if not in accordance with the then applicable Napoleonic Mining Law of 1810 a concession had been applied for and granted allowing to exploit this discovery. From this point of view, admittedly a lawyer’s view, the award of the concession, which was named Groningen, should be considered to be the actual starting point for the aforesaid development.On 1 July 1961 NAM submitted its application for a concession based on its Slochteren discovery and with this submission the negotiations started between the Netherlands government on the one side and NAM and its two shareholders, viz. Shell and Exxon, on the other side, on the terms and conditions to be incorporated in the applied for concession. On the government’s side attention was focused on two aspects: how to integrate the natural gas discovered into the economy of the country and how to involve the State in the production and disposal thereof. From the outset the government intended, that the State’s interests should be represented by the Staatsmijnen in Limburg (State Mines) in order to give this coal mining enterprise a future outside and independent from its ailing coal mining business in the Province of Limburg. To this end the government arranged for State Mines to enter into a maatschap (partnership) with NAM. In this partnership State Mines would get a 40% participating interest, leaving 60% for NAM. The concession would be granted to NAM, but the latter would be obliged to produce the natural gas reserves contained within the concession for the account and responsibility of the partnership. The partnership would be managed by State Mines with a 50% voting right and by NAM’s two shareholders each with a 25% voting right.In the deed of concession, which was granted on 30 May 1963, it is stipulated, that any natural gas not needed by the concessionaire for its own operations should be sold to a corporation to be designated by the Minister and the articles of association of which would require the latter’s approval. This corporation, named the NV Nederlandse Gasunie (the Gasunie), was established on 6 April 1963. Its shareholders were (and still are) State Mines (now Energie Beheer Nederland (EBN)) with a 40% shareholding interest, the two shareholders of NAM, each with a 25% interest, and the State itself with a 10% interest. The Gasunie is allowed to realise from its business of buying, transporting and selling natural gas an after tax profit of NGL 80 million per year. Any surplus revenues are transferred to NAM (the transfer sum) in payment of the gas delivered by NAM.The concession area comprises about 2,970 square km, covering the territory of the Province of Groningen and the territorial waters adjacent to the Province. The concession area includes part of the Waddenzee, an area in respect of which special environmental/zoning rules and regulations are in force. As a matter of fact any exploitation of the gas reserves situated in that area is ruled out, at least for the foreseeable future.The concession area also includes an area described as the Common Area in the Supplementary Eems I Dollard Agreement of 14 May 1962. Under the terms of this Agreement natural gas produced from the gas reserves situated in the Common Area had to be shared with German concessionaires. NAM was appointed the operator for implementing the provisions of the Agreement.A certain varying amount of subsidence is experienced throughout the concession area. In this matter the partnership agreed to compensate, up to a certain financial limit, third parties which incurred costs or suffered damage in connection with said subsidence.

Resistivity imaging of shallow salt with magnetotellurics as an aid to prestack depth migration

Currently NAM (Nederlandse Aardolie Maatschappij B.V.) is undertaking a large Pre-Stack Depth Migration (Pre-SDM) campaign over several salt-related prospects in the Netherlands, two of which, Broek and Ommelanderwijk, are located in fig. 1. To build proper Pre-SDM models of salt domes it is essential to have accurate knowledge of the geology in the shallow subsurface. Using data acquired in a conventional 3D seismic acquisition geometry, with typical 400-500 m line spacing, it is often difficult to image the top of shallow salt domes accurately in the 0-500 m depth range. This problem can be seen clearly in Fig. 2, where a seismic section through the Broek salt dome is displayed.

State-of-the-art of NORM nuclide determination in samples from oil and gas production: Validation of potential standardization methods through an interlaboratory test programme

Gas and oil companies frequently encounter build up of Naturally Occurring Radioactive Material (NORM) in their production and processing facilities. In the Netherlands NORM is subject to strict national regulations and, consequently, installations have to be screened on a regular basis. The availability of accurate and reliable NORM sampling and analysis techniques is therefore essential. A number of years ago, the “Nederlandse Aardolie Maatschappij B.V.” (NAM) actively initiated an investigation on analysis techniques for NORM samples from gas and oil companies. Within this framework, Shell Research Amsterdam organized a four-stage interlaboratory test programme in which representative samples of increasing complexity were analyzed by a number of Dutch institutes. Whereas a large spread in results was observed in the first stage, results in the last stage deviated less than ±10% from the values certified by an independent referee institute, even for comple, sludge samples. It was found that in particular the use of different values for the γ-yields and branching ratios amongst the institutes was responsible for the initial spread.

Subhorizontal Drilling, L13 Block Central Offshore Netherlands: Remedial Action for Underperforming Rotliegende Gas Fields

The first development well in the L13-FE gas field showed a rapid production decline resulting from a marked pressure depletion. Material balance data indicated less than 10% of the expected volumetric reserves to be connected. This poor connectivity is thought to be due to compartmentalization by minor strike-slip faults, as confirmed by lineations on seismic attribute maps. Fault-related diagenesis and a limited number of scattered, stratigraphically isolated prolific layers, diminishing the vertical permeability, can also contribute to the disappointing well performance. The well was sidetracked subhorizontally with the aim to connect a larger number of the scattered prolific sands, different fault compartments and possible open fracture systems. The reservoir section was drilled with graded rock salt mud in order to minimize formation impairment. During drilling of the 500 m long, 5 7/8 in. subhorizontal section, numerous problems were encountered due to mechanical failures and the heterogeneous nature of the reservoir. Slim-hole equipment failures also necessitate a second sidetrack. A significant amount of prolific sand was encountered and the presence of subseismic faults was recognized from log correlations. The well is producing 1.3 x 10[sup 6]m[sup 3]/d, which is above expectation considering that only 60% of the well could be completed.more » Nederlandse Aardolie Maatschappij's first attempt to challenge such geologically complex, labyrinth-type reservoirs by subhorizontal drilling therefore can be considered successful.« less

Blanket 3-D Coverage-Its Successful Application in Exploring a Mature Area, Central Dutch Offshore

In the K and L blocks of the Dutch sector of the southern North Sea, the Rotliegende Sandstone forms the main objective. Drilling started in 1968, and to date 36 Rotliegende gas fields have been discovered in Nederlandse Aardolie Maatschappij (NAM) operated acreage with volumes in place ranging between 2 and 50 x 10[sup 9]m[sup 3]. Approximately 70% of these fields were discovered using two-dimensional seismic, but as exploration progressed an increasing number of wells were found water bearing. The main cause of failure is lack of structural integrity, due to high Rotliegende fault density and highly variable overburden dominated by Zechstein salt and Chalk grabens. Three-dimensional (3-D) seismic acquisition started in 1981 but at first was typically limited to small production surveys covering existing gas fields. In 1986, acquisition of block-wide exploration 3-D surveys began. This has resulted in a present-day coverage of some 5000 km[sup 2], representing 95% of NAM-operated central offshore K and L blocks. Interpretation of these surveys revealed many undrilled structures, inspiring a second phase of exploration drilling with a high success ratio of 80%. As drilling activity progressed in the earliest covered blocks, however, a number of structurally conclusive dry wells were drilled, andmore » remaining individual prospects are small. Therefore, a third exploration phase now has started, concentrating on hydrocarbon habitat reviews making use of detailed 3-D interpretation of seismic attributes. The reconstruction of tectonic history and and updated charge model are expected to lead to an improved definition of remaining potential in these mature blocks.« less

Successful Integration of 3-D Seismic and Multidisciplinary Approaches in Exploring the Zechstein 2 Carbonates in Northeast Netherlands

Nederlandse Aardolie Maatschappij has been actively involved in the exploration of the Zechstein 2 carbonate play for over 40 yr. This exploration effort, concentrated mainly in the Drenthe and Schoonebeek area of northeast Netherlands, has resulted in the discovery of 20 gas fields with cumulative reserves of more than 40 x 10[sup 9] m[sup 3] of gas. The wealth of subsurface data collected in the exploration and development of these fields has lead to the establishment of detailed depositional and diagenetic models of the Zechstein 2 carbonates. More recently, extensive three-dimensional seismic coverage, the integration of lateral prediction techniques, and detailed fracture studies in cores have provided powerful predicting tools in the comprehension and exploitation of the play. Successful integration of the various disciplines now allows exploration of subtle low-relief structures in the mature Zechstein hydrocarbon province and helps target directional exploration and development wells.

The Bunter Gas Play and its Seismic Expression in the West Netherlands Basin

The Lower Triassic Bunter gas play is a major exploration objective in the West Netherlands Basin with proven gas reserves of about 65 x 10[sup 9] m[sup 3]. The upper and middle Bunter reservoirs consist of continental clastics. Hydrocarbons are trapped mainly in horsts and tilted fault blocks, created during the Late Jurassic. Many structures suffered Late Cretaceous to Early Tertiary inversion due to convergent oblique-slip movements. Top and lateral seals are provided by marls and (anhydritic) claystones of the Muschelkalk and Keuper formations and shales of the Jurassic Altena Group. The main hydrocarbon type is gas originating from the underlying Carboniferous Coal Measures; and oil rim is present in some traps. The most important exploration risks are poor reservoir quality in areas of strong inversion and fault seal integrity. During the last 10 yr, Nederlandse Aardolie Maatschappij drilled almost 40 Bunter exploration wells and acquired about 3300 km[sup 2] of 3-D seismic, both onshore and offshore. Three-dimensional seismic data, although variable in quality due to the different sources used in this urbanized area, has greatly improved the structural definition of the Bunter play. Seismic amplitude anomalies, generally conformable with structural closures, have been identified in the south, the areamore » of best reservoir development. Minor changes in amplitude and wavelet character on seismic correspond with the seismic expression of gas/water contacts from Bunter modeling studies.« less

Land Subsidence Above Compacting Oil and Gas Reservoirs

Notable subsidence above producing oil and gas fields is the exception rather than the rule. A simple procedure is outlined to single out the exceptional but real problem areas. This exercise in potential-problem analysis shows that the huge Groningen gas field in The Netherlands is a candidate for causing subsidence troubles in a lowland area. Introduction During the last 20 years, the Royal Dutch/Shell Group has conducted extensive investigations into the phenomenon of reservoir compaction and subsidence. These have included research projects to study subsidence above Bolivar Coast oil reservoirs in Venezuela and to examine the huge Groningen gas reservoir in The Netherlands. The latter investigation was conducted by a team of specialists from both the Koninklijke/Shell Exploratie en Produktie Laboratorium (KSEPL) and BV Nederlandse Aardolie Maatschappij (NAM), the latter being the producing company owned jointly by Shell and Esso. Details of the Groningen investigation are published elsewhere but as it may have consequences for other operating companies working in lowland and other subsidence-prone areas, we shall consider here the causes of subsidence above hydrocarbon-producing reservoirs in a more general way, and review the state of the art of its prediction. A simple method will be presented for estimating the order of magnitude of both compaction and the accompanying subsidence. Application of this method, which can be used to explore the need for an investigation in depth, requires hardly any specialist knowledge. The objective is twofold: to demonstrate that land subsidence due to hydrocarbon production seldom leads to serious subsidence, and production seldom leads to serious subsidence, and to pinpoint the few potential problem areas. Earlier Field Observations The literature on subsidence deals mainly with a few notable examples, such as the Goose Creek oil and gas field in Harris County, Tex., where dramatic subsidence occurred between 1918 and 1925, and the Wilmington field below Long Beach, Calif., where almost 10 m of subsidence was experienced in 1960. Further subsidence could be avoided in this latter case after unitization and pressure maintenance as a result of water injection. More recently, a search for additional, documented surface depressions over oil and gas fields in the U. S. was reported by Yerkes and Castle. This search revealed only a few other significant cases, mainly fields close to Wilmington, such as those at Buena Vista, Huntington Beach, and Inglewood. From this concentration of subsidence bowls, it may be inferred that such events are somehow related to a similarity in reservoir conditions. Shell has been confronted only once with a major land-subsidence problem. It is related to the production of oil and gas in Venezuela, where subsidence above a number of important oil reservoirs bordering Lake Maracaibo is a constant phenomenon, and huge dykes have been built to protect the coastal area from flooding. Its cause is discussed by Van der Knaap and Van der Vlis. Subsidence data for oil and gas fields outside the Americas are very scarce indeed. Okumara and Hirono describe a case from the Niigata district of Japan that results from the production of methane dissolved in water. In Italy, AGIP has been accused of contributing to subsidence in the Po Delta by producing from a number of gas fields. JPT P. 734