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The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
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Abstract This paper presents the case histories of four adjacent development wells drilled through the Zechstein formations in the Southern North Sea (SNS) during '99-'00. A jack-up MODU was used in cantilever mode. Formation pressures encountered ranged from 18.1ppg to 19.25ppg EMW. Brine kicks, believed to be among the most intense in the SNS, were experienced. Of the 4 wells, 2 encountered high-pressure from Plattendolomit formation, while the other two experienced significant pressures from within the Zechstein salt itself. The Zechstein Supergroup is a series of evaporite and carbonate formations formed ca. 250 million years ago. It has presented Southern North Sea drillers with significant problems since drilling began ca. 1965. This paper focuses on the problems associated with the drilling of the Z3 series. These are overpressure; losses; and loss/gain situations. A description of each problem and the industry's current thinking towards them is presented. The recent wells have provided a learning opportunity. The prospect of encountering high-pressure was considered likely. Contingency plans were drawn up and implemented in response to events. The experience gained, as the project progressed, was used to tailor the approach towards the subsequent wells. This iterative process is followed, as each well is drilled, and serves to provide a variety of learning points. These are categorised as 1) Wells Problems and Solutions 2) Practical Problems and Solutions. These cover issues ranging from how to circulate kill mud effectively to determining the volume of influx. The learning is documented and presented as a reference for future developments. Introduction In spite of years of practice brine flows continue to hamstring drilling operations. Marginal fields require tight economic control and confidence to engineer cost-effective solutions to such problems is essential to future developments. How to deal with high-pressure brine flows effectively and thereby minimise associated NPT (Non-Productive Time) is not clear. There appears to be no panacea - each situation requires considered experience to select appropriate action. Surface observations can be misleading and their interpretation subjective. Understanding events and implementing effective measures are highly desirable objectives. Shared knowledge and experience is crucial if Zechstein drilling performance is to improve. To this end this case study aims to ensure learning is captured from the rig activities associated with a recent series of high-pressure brine kicks. The study will initially review the open literature, interview engineers and field personnel, and develop a synopsis of the industry's present thinking towards brine flows. Against this backdrop of understanding the surface observations from the recently drilled wells, the responses to them, and their effects will be analysed. This study will share the learning wrought from the experience of the development wells and serve to provide onshore and offshore personnel with an informed view, based on practical experiences, with which to assess and manage their circumstances. Zechstein Problems The Zechstein's problems vary across the Southern North Sea basin. Towards its centre the evaporites can be extremely mobile. Stuck pipe, collapsed casing, and hole washouts are common. The development wells in this study were drilled at a location closer to the basin's margin. Salt mobility did not appear to be an issue. However, the Z3 series of formations can, and did, present an array of problems. These included significant overpressure, losses, and loss/gain events. A brief view of the industry's understanding of these problems is presented below.
Gerling, P. (Federal Institute for Geosciences and Natural Resources (BGR), Germany) | Kockel, F. (Federal Institute for Geosciences and Natural Resources (BGR), Germany) | Krull, P. (Federal Institute for Geosciences and Natural Resources (BGR), Germany) | Stahl, W. J. (Federal Institute for Geosciences and Natural Resources (BGR), Germany)
Abstract. The reserves of natural gas in Germany are limited. Hence, new exploration concepts are necessary to meet the future requirements. The BGR has studied in collaboration with German and European universities and the Germany oil industry the possibilities for deep gas generation in northern Germany. The term ‘deep gas’ defines natural gas generated from organic matter in pre-Westphalian Sediments. A multidisciplinary geological and geochemical approach has been followed in this research program: Structural geology of the pre-Permian and palaeogeographical studies of potential pre-Westphalian source rocks. Organo-petrographical studies in order to set up maturity maps of Base Zechstein and Top pre-Permain. Modelling of burial and subsidence. Source rocks evaluation including hydrous and anhydrous pyrolysis experiments. Extensive gas and isotope geochemistry on reservoir gases and pyrolysis products. The integration of all results verify that the prerequisites for the existence of deep gas in Germany are fulfilled in several cases and allow ‘perspective areas’ to be defined. INTRODUCTION As a contribution to securing the mid and longterm domestic supply of natural gas, but also in the run-up to industrial exploration, the Federal Institute for Geosciences and Natural Resources (BGR), has being carrying out the interdisciplinary study ‘Deep Gas’ (Stahl et al. 1996). The aim was to gain evidence for the existence of deep gases of pre-Westphalian origin, to narrow down their genetic origin, to estimate the timing of gas generation and to highlight the circumstances under which deep gases in the North German Basin can be expected. DISTRIBUTION OF PRE-WESTPHALIAN SOURCE ROCKS Early Paleozoic source rocks and Devonian source rocks certainly play only a subordinate role in the North German Basin. The source rock potential in the pre-Westphalian carboniferous Sediments however is extremely interesting, especially since the natural gas fields Altmark-Wustrow and Alfeld-Elze are situated outside the distribution of coal-bearing Westphalian. In the Dinantian, coal-bearing delta-plain and lacustrine deposits as well as alternations of shallowmarine and deltaic deposits (Yoredale facies) with source rock potential are limited to the northern and north eastern fringe of the depositional area (Mid North Sea high, Ringköbing-Fyn high, Lublin area). Intra-platform basins, known from Central Britain and containing marine and non-marine source rocks, may also occur in the southern North Sea basin and in the north German plains. South of the grabendissected carbonate platform the large, starved Rheno-Hercynian basin with marine source rocks (alum shales, silicious shales) extended from the Rhine to Upper Silesia.
Integrating New Technology - The Development of the Barque Extension Structure. Abstract The Barque Extension PL well head jacket recently came on stream with the opening up of well PL01 on 31/10/95. This was a successful culmination of the efforts of the Southern Field Unit teams that designed and executed this project on time and under budget. The reservoir will supply gas to the Bacton plant over the next 25+ years forming an important part of Expro's long term gas supply from the Southern North Sea basin. Review of the evolution of the subsurface development plan highlights the effective integration of innovative technology to improve Project economics. Geological Setting Barque Extension is situated in the Greater Sole Pit area of the Southern North Sea some 50 miles NNE of the Bacton gas plant. (Figure 1.) The reservoir is a fault bounded southward dipping structure in the Lower Permian Rotliegend sands. These aeolian sandstones form the main reservoir body, consisting of dune, interdune and sabkha deposits. The reservoir is subdivided based into the upper A-sand unit (mediocre reservoir properties, but carrying a large part of the reserves), the underlying B-sand (dune slipface sands with better reservoir properties allowing much higher production rates) and the basal C-sand unit (the poorest properties but only occasionally above the GWC). Palaeo-burial at double the present depth of + 8000 ft tvss has reduced the porosity and permeability, resulting in average in-situ effective matrix permeabilities of only 50 D. Faulting and folding during the burial and subsequent inversion of the reservoir resulted in a complex natural fracture system of NW-SE striking faults. Although the fracture swarms are far apart, they provide a good connection between dune bodies, thus improving transmissibility in both vertical and horizontal directions. Field Infrastructure and Operating Philosophy There are existing fields in the area, which supply gas to the Clipper complex, which is the offshore end of the Sole Pit Offshore Transportation System (SPOTS), that transports the (wet) gas back to the Bacton shore terminal. See Figure 2. The Clipper complex is one of Shell/Esso's 3 nodal platforms in the Southern North Sea that are permanently manned, with the other satellite platforms operated as Normally Unmanned, with only emergency overnight accommodation. Visits to the Normally Unmanned Installations (NUI) are performed by intervention teams as required. Against the background of this operating philosophy the platform for Barque Extension structure was designed to be a NUI tied back to the SPOTS export system. History of Well Planning The original development concept (1988) for the Greater Sole Pit area assumed that the majority of reservoir potential would result from direct intersection of deviated wells with natural fractures and indirectly through massive hydraulic fracture treatments. It was estimated that up to 40% of the wells would fail to intersect fractures even after stimulation and only produce at low rates from the matrix. Early deviated and fracture stimulated wells displayed poor inflow performance and the approach was therefore changed to horizontal wells that could increase the probability of intersecting the slipface sands and open fracture networks. The Development Plan for the Barque Extension structure (Oct. '93) therefore called for 8 single horizontal wells, with a projected drilling cost of some 60 million. The plan has matured further, being reduced to three single horizontal and three dual lateral horizontal wells. The projected drilling cost is now of the order of 37 million, still accessing the same reserves. See Table A. P. 483
This is completely satisfactory to the interpreter because it Depth maps are an important component in the process incorporates the known relationship with seismic of finding gas in the Southern Gas Basin.
EXTENDED ABSTRACT Extending the geographic scope of offshore exploration has traditionally been perceived as the frontier for offshore petroleum development. Correspondingly, focus in assessing world offshore petroleum potential has been on assessing the potential of unexplored or lightly explored areas. This focus is highly understandable. The history of offshore development is one of pushing back the geographic frontier of exploration. Offshore development began with gradual steps seaward into shallow waters immediately offshore known onshore producing provinces such as the Mississippi Delta, the Maracaibo Basin, the Arabian/Persian Gulf, the Ventura Basin, the East Natuna Basin, and the Niger Delta. By the mid-1960's, the offshore industry had attained sufficient competence and confidence to tackle offshore basins with little or no corresponding onshore production such as Cabinda, Gippsland, Gulf of Suez and Southern North Sea basins during the late 1960's, Carnarvon, Northern North Sea, and Sverdrup basins in the 1970's, the Beaufort Sea, Campos Basin, Gulf of Campeche, and Northeast Newfoundland Shelf during the late 1970's, and the central and northern Norwegian coastal basins in the early 1980's. This continuing record of progress in the offshore industry over the past several decades now poses a major problem. The geographic frontier of offshore exploration has been pushed back so far that it will soon disappear. Practically every geologically attractive sub polar offshore province has now experienced exploratory drilling. In the process, many offshore basins are now known to have unfavorable geologic conditions and thereby lack major potential. By the end of this decade, nearly all of the Arctic offshore basins other than deepwater ones in continuous pack ice regions will also have been drilled. If the geographic frontier of exploration were the only frontier facing the offshore industry, the future would look bleak. Fortunately, it is not. Increasingly, the ultimate size of offshore petroleum resources will be determined by how successful the offshore industry is in pushing back other frontiers. Three interrelated frontiers the , the , and the are the critical frontiers facing the offshore industry during the next decades. The principal conceptual frontier requires a change of focus for offshore industry activity. Traditionally, the industry has thought that the best way to add new reserves is to and new fields. But, it has become increasingly apparent onshore that the most effective way to add reserves is to find and develop more reserves in old fields. Offshore, the use of close-grid seismic for field development and subsequent re-exploration offers opportunities for new pool discoveries and better drainage f known reservoirs by selective infill drilling and peripheral subsea completions. While the existing infrastructure is still in place, secondary and enhanced oil recovery potential offshore needs to be pursued vigorously as well.
Abstract Current exploration in the North Sea is described and latest estimates of the reserves of oil and gas are given. The field development program is reviewed and forecasts of production presented. The principal economic constraints are identified and examined against the recent position taken by tile UK Government on tax and participation. Events during the past few years have combined to make the oil developments in the North Sea, paticularly interesting. Technically, the deep and hostile water of this latest major new oil province have demanded new solutions for new problems. Economically, the incidence of runaway inflation on high-cost development at a time when massive new taxes have been introduced to take advantage of high oil prices has created unique financial stresses. Politically the impact of the development on industrial countries has bud considerable social and national repercussions within a short period. History SOME 6,000 exploration wells were drilled onshore in Western Europe during the period 1920–59, resulting in a maximum total production of only 250,000 bbls/ day and few important gas discoveries. There was little basis, therefore, for anticipating spectacular hydrocarbon accumulation. In 1959 however, the giant gas field of Slochteren was discovered in the Netherlands, in a geological setting which immediately suggested that similar prospects might lie under the North Sea. The Southern North Sea basin was the first to be explored, and has subsequently proved to contain large gas reserves in the Permian sandstones similar to those of Slochteren. Five commercial gas fields have been put on production and eighteen other gas strikes have been made in UK waters. Not all are of commercial proportions, but none can apparently be developed, largely due to the low prevailing gas price negotiated with the monopoly buyer, the British Gas Corporation. Several gas fields have been found off the Netherlands and one of these is currently being developed. The high continental prices will encourage further development here. So far, 379 exploration and appraisal wells have been drilled in the southern part of the North Sea, including Danish waters, with a success ratio of approximately 1 in 20. The Northern North Sea is predominantly an oil prospective region of younger geological age and now appears to be one of the most prolific areas, for its size, in the world. The basin covers both Norwegian and UK offshore acreage and so far exploration has been limited to the area south of latitude 62"N. There are three major types of prospect in this basin. In order of increasing age, the first and youngest prospect is in the Lower Tertiary sandstones, of which the Forties Field is an example. The second prospect (although the first discovered) is in the domed and fractured Upper Cretaceous and Danian limestone, typified by the Ekofisk Field. The third major prospect, and the most important, is in the. Jurassic sandstones in the northern part of the basin. as evidenced by the Brent group of oilfields.