Maximising Chemical Placement in Complex Wells
Abstract: fax 01-972-952-9435. AbstractThe effective placement of chemical squeeze treatments in heterogeneous wells and long reach horizontal wells has proved a significant challenge, with various factors including heterogeneity, crossflow and pressure gradients between otherwise non-communicating zones within the well, all contributing to an uneven placement of the scale squeeze treatment into the reservoir. Work recently presented by the authors has however illustrated the potential benefits of using modified injecti… Show more
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The effective placement of chemical squeeze treatments in heterogeneous wells and long reach horizontal wells has proved a significant challenge, with various factors including heterogeneity, crossflow and pressure gradients between otherwise non-communicating zones within the well, all contributing to an uneven placement of the scale squeeze treatment into the reservoir. Current methods to circumvent these problems often rely on extremely expensive coiled tubing operations, staged diversion (temporary shut off) treatments or by designing treatments to deliberately overdose some zones in order to gain placement in other (e.g. low permeability) zones. As part of a multi-sponsor Joint Industrial Project at Scaled Solutions Ltd., a series of papers has been released in recent years describing the development of a near wellbore placement model, Place iTTM v. 3.0 designed to model properly the flow behaviour of both Newtonian and non-Newtonian injection fluids in the near wellbore region. In this paper, we describe the extension of previously reported laboratory dual linear core flood placement tests technology to the radial case, in which the flow behaviour of the injected fluids more closely resembles that in the near wellbore region. By extending the laboratory test technology in this way, we are able to examine directly aspects of fluid propagation in a manner which directly correlates to field behaviour. We will present laboratory test results comparing the placement of fluids with different properties and show how the results from these tests concur with previous findings and calculations from dual linear placement core flood tests, and we will further expand on the importance of non-conventional fluids for achieving improved chemical placement in complex wells. Introduction Chemical placement in complex and heterogeneous wells such as subsea wells, highly compartmentalised reservoirs, deviated and horizontal wells can be a challenging operation, with factors such as permeability contrast, pressure gradient, crossflow etc. all contributing to the heterogeneous nature of these wells. This challenge stems from the difficulty often experienced in the optimisation of the placement operation to achieve effective and even distribution of the treatment chemical throughout the well zones. To achieve more even placement in different non-communicating zones in these environments, the industry has for long relied on a number of techniques such as coiled tubing operations 1–3, staged diversion 1, 3–6 and deliberate chemical overdosing 3. Such techniques can suffer from a number of drawbacks, including higher costs, more technically demanding operations and, at times, limited applicability. In a series of recent papers,7,8 the use of viscous shear thinning injection fluids to effect more even placement in such complex wells via standard bullhead treatments has been described. To allow predictive modelling of chemical placement using such viscous shear thinning fluids, a near wellbore simulator (Place iT v. 3.1) has been developed as part of a Joint Industrial Project. This simulator is able to model Newtonian and non Newtonian fluid behaviour and propagation in highly heterogeneous reservoirs or wells. In effect, the model can give a quantitative assessment of fluid placement in a heterogeneous reservoir environment, giving the design and field engineers access to realistic assessments of the placement and subsequent chemical return behaviour of proposed field/well treatments. To validate the simulator, core flood experiments using two linear cores in a dual parallel linear arrangement were designed and implemented in the laboratory.7–9 These tests investigated the placement behaviour of Newtonian and viscous shear thinning fluids when faced with permeability contrasts, pressure contrasts or both pressure and permeability contrasts. The placement results observed in these experiments agreed closely with the Place iT simulator predictions of these linear flow tests, providing direct experimental evidence of the appropriateness of the models treatment of shear thinning fluid behaviour in reservoir cores.7–8
The effective placement of chemical squeeze treatments in heterogeneous wells and long reach horizontal wells has proved a significant challenge, with various factors including heterogeneity, crossflow and pressure gradients between otherwise non-communicating zones within the well, all contributing to an uneven placement of the scale squeeze treatment into the reservoir. Current methods to circumvent these problems often rely on extremely expensive coiled tubing operations, staged diversion (temporary shut off) treatments or by designing treatments to deliberately overdose some zones in order to gain placement in other (e.g. low permeability) zones. As part of a multi-sponsor Joint Industrial Project at Scaled Solutions Ltd., a series of papers has been released in recent years describing the development of a near wellbore placement model, Place iTTM v. 3.0 designed to model properly the flow behaviour of both Newtonian and non-Newtonian injection fluids in the near wellbore region. In this paper, we describe the extension of previously reported laboratory dual linear core flood placement tests technology to the radial case, in which the flow behaviour of the injected fluids more closely resembles that in the near wellbore region. By extending the laboratory test technology in this way, we are able to examine directly aspects of fluid propagation in a manner which directly correlates to field behaviour. We will present laboratory test results comparing the placement of fluids with different properties and show how the results from these tests concur with previous findings and calculations from dual linear placement core flood tests, and we will further expand on the importance of non-conventional fluids for achieving improved chemical placement in complex wells. Introduction Chemical placement in complex and heterogeneous wells such as subsea wells, highly compartmentalised reservoirs, deviated and horizontal wells can be a challenging operation, with factors such as permeability contrast, pressure gradient, crossflow etc. all contributing to the heterogeneous nature of these wells. This challenge stems from the difficulty often experienced in the optimisation of the placement operation to achieve effective and even distribution of the treatment chemical throughout the well zones. To achieve more even placement in different non-communicating zones in these environments, the industry has for long relied on a number of techniques such as coiled tubing operations 1–3, staged diversion 1, 3–6 and deliberate chemical overdosing 3. Such techniques can suffer from a number of drawbacks, including higher costs, more technically demanding operations and, at times, limited applicability. In a series of recent papers,7,8 the use of viscous shear thinning injection fluids to effect more even placement in such complex wells via standard bullhead treatments has been described. To allow predictive modelling of chemical placement using such viscous shear thinning fluids, a near wellbore simulator (Place iT v. 3.1) has been developed as part of a Joint Industrial Project. This simulator is able to model Newtonian and non Newtonian fluid behaviour and propagation in highly heterogeneous reservoirs or wells. In effect, the model can give a quantitative assessment of fluid placement in a heterogeneous reservoir environment, giving the design and field engineers access to realistic assessments of the placement and subsequent chemical return behaviour of proposed field/well treatments. To validate the simulator, core flood experiments using two linear cores in a dual parallel linear arrangement were designed and implemented in the laboratory.7–9 These tests investigated the placement behaviour of Newtonian and viscous shear thinning fluids when faced with permeability contrasts, pressure contrasts or both pressure and permeability contrasts. The placement results observed in these experiments agreed closely with the Place iT simulator predictions of these linear flow tests, providing direct experimental evidence of the appropriateness of the models treatment of shear thinning fluid behaviour in reservoir cores.7–8
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