Valhall Field: Microfracture Acquisition Using Wireline-Formation-Tester Tools To Validate Fracture Confinement
Abstract: TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractProppant fractures have been performed in the Valhall Field since 1986 with over 200 proppant fractures completed to date. Prior to the development of the flank regions of the Valhall field in April of 2003 the majority of the proppant fractures were executed in the crest of the field and were confined to the producing interval due to considerable pressure depletion. It was identified that 50% of the new wells in the flank would be completed in near original … Show more
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Cited by 6 publications
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TX 75083-3836 U.S.A., fax 01-972-952-9435. AbstractNon-Darcy and multiphase flow effects in hydraulic fractures have been well documented during the last several years. The pressure losses due to these phenomena are widely accepted to be of great significance in most gas well completions in the United States and elsewhere. While the importance in gas wells is evident, the authors pose the question of whether non-Darcy and multiphase flow effects are of concern in typical oil wells in Russia.For the analysis, the authors evaluate three primary categories of Russian production wells: gas wells, oil wells producing above the bubble point, and oil wells producing below the bubble point. For each category, the authors describe the significance of non-Darcy and multiphase flow effects using fracture flow theory as well as state-of-the-art fracture production models. This paper will illustrate that non-Darcy and multiphase flow effects can substantially decrease the production potential of gas wells, as well as many of the oil wells found in Russia that are producing below the bubble point.Historically, Russian oil wells have been intentionally operated above the bubble point. However, more aggressive well designs have recently been shown to increase production by over three-fold. The authors explore the economics of producing these wells below the bubble point and show that for these more aggressive strategies, the effects of non-Darcy and multiphase flow can be significant and should be accommodated during fracture design.The authors propose solutions for mitigating these effects through various modifications to the fracture design including the impact of proppant selection on performance. Several operators within Russia have already successfully accounted for these phenomena in their fracture designs, and new field examples are explored, analyzed and presented in the paper. Recent field results are presented for Gazpromneft's Achimovskoya formation BV8 in Tomsk region (Western Siberia) and BP-TNK's field near Buzuluk in the Orenburg region (Volga-Urals). The results found here are compared to published results from the Achimovskoya sandstone in the Kalchinskoye oilfield, the BP12 formation of the Vyngayakhinskoe field, the Priobskoye and Sugmutskoe oilfields, and Gazprom's Yamburskoe gas condensate development.
TX 75083-3836 U.S.A., fax 01-972-952-9435. AbstractNon-Darcy and multiphase flow effects in hydraulic fractures have been well documented during the last several years. The pressure losses due to these phenomena are widely accepted to be of great significance in most gas well completions in the United States and elsewhere. While the importance in gas wells is evident, the authors pose the question of whether non-Darcy and multiphase flow effects are of concern in typical oil wells in Russia.For the analysis, the authors evaluate three primary categories of Russian production wells: gas wells, oil wells producing above the bubble point, and oil wells producing below the bubble point. For each category, the authors describe the significance of non-Darcy and multiphase flow effects using fracture flow theory as well as state-of-the-art fracture production models. This paper will illustrate that non-Darcy and multiphase flow effects can substantially decrease the production potential of gas wells, as well as many of the oil wells found in Russia that are producing below the bubble point.Historically, Russian oil wells have been intentionally operated above the bubble point. However, more aggressive well designs have recently been shown to increase production by over three-fold. The authors explore the economics of producing these wells below the bubble point and show that for these more aggressive strategies, the effects of non-Darcy and multiphase flow can be significant and should be accommodated during fracture design.The authors propose solutions for mitigating these effects through various modifications to the fracture design including the impact of proppant selection on performance. Several operators within Russia have already successfully accounted for these phenomena in their fracture designs, and new field examples are explored, analyzed and presented in the paper. Recent field results are presented for Gazpromneft's Achimovskoya formation BV8 in Tomsk region (Western Siberia) and BP-TNK's field near Buzuluk in the Orenburg region (Volga-Urals). The results found here are compared to published results from the Achimovskoya sandstone in the Kalchinskoye oilfield, the BP12 formation of the Vyngayakhinskoe field, the Priobskoye and Sugmutskoe oilfields, and Gazprom's Yamburskoe gas condensate development.
Summary Non-Darcy and multiphase flow effects in hydraulic fractures have been well documented in the last several years. The pressure losses caused by these phenomena are accepted widely to be of great significance in most gas-well completions in the United States and elsewhere (Palisch et al. 2007; Forchheimer 1901; Milton-Tayler 1993a; Penny and Jin 1995; Flowers et al. 2003; Miskimins et al. 2005; Handren et al. 2001; Lolon et al. 2004; Vincent 2004; Olson et al. 2004). Although the importance in gas wells is evident, the authors pose the question of whether non-Darcy and multiphase flow effects are of concern in typical oil wells in Russia. For the analysis, the authors evaluate three primary categories of Russian production wells: gas wells, oil wells producing above the bubblepoint, and oil wells producing below the bubblepoint. For each category, the authors describe the significance of non-Darcy and multiphase flow effects by use of the fracture-flow theory and state-of-the-art fracture-production models. This paper will illustrate that non-Darcy and multiphase flow effects can substantially decrease the production potential of gas wells and the many oil wells found in Russia that are producing below the bubblepoint. Historically, Russian oil wells have been operated intentionally above the bubblepoint. However, more-aggressive well designs have recently been shown to increase production more than threefold. The authors explore the economics of producing these wells below the bubblepoint and show that for these more aggressive strategies, the effects of non-Darcy and multiphase flow can be significant and should be accommodated during fracture design. The authors propose solutions for mitigating these effects with various modifications to the fracture design, including the impact of proppant selection on performance. Several operators within Russia have already successfully accounted for these phenomena in their fracture designs, and new field examples are explored, analyzed, and presented in the paper. Recent field results are presented for Gazpromneft's Achimovskoya formation BV8 in the Tomsk region (western Siberia) and BP-TNK's field near Buzuluk in the Orenburg region (Volga-Urals). The results found here are compared to published results from the Achimovskoya sandstone in the Kalchinskoye oil field, the BP12 formation of the Vyngayakhinskoe oil field, the Priobskoye and Sugmutskoe oil fields, and Gazprom's Yamburgskoe gas-condensate development. Introduction In the last decade, emphasis has been placed increasingly on the conductivity of the proppants used in fracture stimulations, especially for medium-to-high-permeability formations. The conductivity of the fracture can be calculated by finding the product of the permeability of the fracture and the fracture width. It can be represented by the following equation:[Eqn 1] Typically, analysis of the flow potential of a well has involved the determination of the dimensionless fracture conductivity (Fcd) relating the flow potential of the fracture to that of the reservoir. Fcd is calculated by use of the following equation:[Eqn 2] For steady- or pseudosteady-state flow in oil wells, several authors, including Prats (1961) and McGuire and Sikora (1960), have developed correlations that enable the engineer to use Fcd to predict the benefits of the fracture stimulation, yielding a method that balances fracture half-length with fracture conductivity for stimulation design. Fig. 1 illustrates Prats' correlation (where kp is the permeability of the fracture, kfrac, and kf is the permeability of the formation, kform). Increasing the Fcd of the fracture leads to an enlargement of the effective wellbore radius (rw '/Xf). However, after an Fcd of ˜10, the incremental effective radius slows for a given increase in Fcd. Although these correlations continue to serve the industry well, it is critical that a realistic conductivity be used when calculating Fcd (Pearson 2001). Fig. 2 shows the "reference" or "laminar" conductivity for several different intermediate-density ceramic proppants commonly used in Russia. In this figure, the proppant has been subjected to 4,000-psi stress (272 atm). However, it is critical to note that these reference values have not been corrected for non-Darcy or multiphase flow, gel damage, filter cake, fines plugging, cyclic stress-loading, long-term proppant degradation, and many other phenomena that will increase the pressure losses within the fracture. Vincent et al. (1999) have pointed out that the American Petroleum Institute (API) conductivity test used in many fracture-production models significantly overpredicts the conductivity of proppant. This can lead to selection of a proppant that appears adequate when evaluated at reference conditions but is actually severely inadequate at realistic producing conditions. Many papers have documented the benefits of increasing the conductivity of hydraulic fractures, in both gas and oil wells, at a variety of production rates and flowing conditions (Vincent 2002; Carbo Ceramics 2007).
Horizontal Well Completion and Stimulation Techniques—A Review With Emphasis on Low-Permeability Carbonates
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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