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The Taranaki district of New Zealand, located in the southwest corner of the North Island, is the center of the country's emerging oil and gas industry. Over the last five years, an active campaign of propped hydraulic fracture stimulation has been performed in the early Miocene and Oligocene sandstones, located towards the south of the Taranaki sedimentary basin. Although hydraulic fracture stimulation is relatively rare in New Zealand, it has shown itself to be highly effective. This is due, in part, to the application of sound scientific and engineering principals, rather than the stochastic approach that is often applied when fracturing. The formations themselves are highly complex and consequently the techniques used for fracturing are at the cutting edge of today's fracturing technology. The results of the programme have significantly benefited from this methodical and progressive approach. This paper deals with the various aspects of fracturing into these formations and the lessons learned, including the equipment and methods used. It also details how the methods have evolved and allowed treatments to increase in both size and effectiveness, using numerous case histories. These detail what can be achieved in an area that is generally unfamiliar with the processes involved, when an existing technology is systematically applied. Introduction The Taranaki Basin1 Figure 1 shows the Taranaki basin, located to the west of the North Island of New Zealand, which comprises an area of approximately 100,000 km2 (62,100 sq miles). Although most of the producing fields are located onshore, the majority of the basin is offshore. The basin contains oil, gas and condensate reservoirs. A stratigraphic column for the basin is given in Figure 10 (see Appendix 1). The geology consists of Cretaceous to Quaternary sandstones up to 9 km (5.6 miles) thick. The basin morphology is composite as a result of several significant episodes of tectonic activity. The main source formations tend to be Cretaceous coaly sediments and early Cenozoic terrestrial and marine sediments. Reservoir formations are late Cretaceous to Eocene terrestrial-paralic-nearshore sandstones, late Cretaceous to Eocene coal measures, Eocene turbidites, fractured Oligocene limestone, Miocene volcaniclastics, Miocene turbidites and Pliocene prograding sands. The Basin is bounded by a major fault to the east, as illustrated in Figure 1 (the Taranaki Fault).
The Taranaki district of New Zealand, located in the southwest corner of the North Island, is the center of the country's emerging oil and gas industry. Over the last five years, an active campaign of propped hydraulic fracture stimulation has been performed in the early Miocene and Oligocene sandstones, located towards the south of the Taranaki sedimentary basin. Although hydraulic fracture stimulation is relatively rare in New Zealand, it has shown itself to be highly effective. This is due, in part, to the application of sound scientific and engineering principals, rather than the stochastic approach that is often applied when fracturing. The formations themselves are highly complex and consequently the techniques used for fracturing are at the cutting edge of today's fracturing technology. The results of the programme have significantly benefited from this methodical and progressive approach. This paper deals with the various aspects of fracturing into these formations and the lessons learned, including the equipment and methods used. It also details how the methods have evolved and allowed treatments to increase in both size and effectiveness, using numerous case histories. These detail what can be achieved in an area that is generally unfamiliar with the processes involved, when an existing technology is systematically applied. Introduction The Taranaki Basin1 Figure 1 shows the Taranaki basin, located to the west of the North Island of New Zealand, which comprises an area of approximately 100,000 km2 (62,100 sq miles). Although most of the producing fields are located onshore, the majority of the basin is offshore. The basin contains oil, gas and condensate reservoirs. A stratigraphic column for the basin is given in Figure 10 (see Appendix 1). The geology consists of Cretaceous to Quaternary sandstones up to 9 km (5.6 miles) thick. The basin morphology is composite as a result of several significant episodes of tectonic activity. The main source formations tend to be Cretaceous coaly sediments and early Cenozoic terrestrial and marine sediments. Reservoir formations are late Cretaceous to Eocene terrestrial-paralic-nearshore sandstones, late Cretaceous to Eocene coal measures, Eocene turbidites, fractured Oligocene limestone, Miocene volcaniclastics, Miocene turbidites and Pliocene prograding sands. The Basin is bounded by a major fault to the east, as illustrated in Figure 1 (the Taranaki Fault).
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractA fully implicit numerical model coupling reservoir and multifractured horizontal well flow dynamics has been developed to investigate the flow behavior and predict the productivity of such systems. The simulator solves simultaneously for pressure distribution within the reservoir and horizontal well domains, while taking into account the friction losses along the wellbore for laminar and turbulent flow conditions. Fractures with distinct properties are placed perpendicular to the wellbore axis and can intersect the well at arbitrary locations. The model is unconditionally stable and can be used to analyze the early transient period as well pseudo-and steady-state conditions. The use of multifractured horizontal wells has been gaining popularity in tight reservoir systems; however, the existing design protocols do not consider wellbore hydraulics that can have a governing role in the performance of the system. The appropriate design of a multifractured well has a definite impact on its performance. The numerical model presented in this paper can be utilized as a design tool towards the optimization of the number, position and penetration lengths of the fractures connected to a horizontal well.The calculated influx and pressure distributions along the wellbore show that solutions can deviate dramatically from the actual behavior if infinite conductivity idealization is used to represent flow dynamics in the horizontal well, and this discrepancy becomes more pronounced with an increase in reservoir permeability. Parametric studies are conducted to evaluate the influence of the number of the fractures in the flow behavior and productivity of the system. The observations and analyses presented in this paper will provide the much needed guidance to engineers who face the daunting task of designing a cost-effective optimum fracturing scheme in horizontal wells completed in formations with different flow characteristics.
fax 01-972-952-9435. AbstractThis paper presents a brief review of the available techniques in the oil and gas industry to complete and stimulate horizontal wells, with emphasis on low permeability carbonates. These techniques can also be applied in non-conventional reservoirs, particularly in tight formations. The paper starts by reviewing the lessons learned in some chalk fields in the North Sea (Dan, Halfdan, South Arne, Valhall and Eldfisk) and in a few pilot projects offshore Brazil (Congro and Enchova). Based on these lessons learned and in the broad literature, the paper devises some considerations on the methodology to select completion and stimulation techniques for horizontal wells. Cased and cemented horizontal wells, in addition to open hole and perforated/slotted liners wells are addressed. The macro aspects of field/area management are stressed as the completion and stimulation drivers. The key parameters for designing, implementing and evaluating horizontal completion and stimulation are presented, emphasizing the most common failures and the controversial aspects. The paper presents a summary of mature field and new scenarios that are candidate to horizontal completion and stimulation in Brazil and other Latin America countries. Then it makes a few comments on the resources available in Latin America to face the mentioned opportunities and related challenges. It is supposed that this brief review will be useful for the low permeability scenarios in Latin America and worldwide. Completion and Stimulation of North Sea Low-Permeability CarbonatesThe North Sea low permeability chalks are taken here as a reference due to the outstanding technological evolution verified there in the last decades. Amongst more than ten fields producing from these reservoirs in the North Sea this paper focuses on the Dan, Halfdan, South Arne, Valhall and Eldfisk fields. The main characteristics of these fields are: shallow waters (43 to 69 m), dry completion, high volumes of OOIP (1.6 to 2.9 billions barrel), low permeability carbonates (0.2 md to 10 md) with microfractures in the central areas (10 md to 120 md), high porosities (up to 48%), soft to very soft chalks, small to medium net pays (15 m to 65 m), high oil saturation (up to 97%), and light oils ( about 36 o API). What most distinguishes these fields is their over-pressured soft chalks which are subjected to a high degree of compaction under pore pressure depletion, resulting in loss of drilling fluids, rapid production decline, well failures and seafloor subsidence. On the other hand the positive effects of rock compaction as a reservoir drive energy, outweigh by far the negative ones. The recovery factor under primary recovery can be as high as 30%. In general the North Sea chalks experienced an evolution from vertical/directional wells stimulated with acid treatments to multiple fractured horizontal wells.
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