Summary This paper presents a new procedure to quantify communication between vertical wells in a reservoir on the basis of fluctuations in production and injection rates. The proposed procedure uses a nonlinear signal-processing model to provide information about preferential-transmissibility trends and the presence of flow barriers. Previous work used a steady-state (purely resistive) model of interwell communication. Data in that work often had to be filtered to account for compressibility effects and time lags. Even though it was often successful, the filtering required subjective judgment as to the goodness of the interpretation. This work uses a more complicated model that includes capacitance (compressibility) as well as resistive (transmissibility) effects. The procedure was tested on rates obtained from a numerical flow simulator. It was then applied to a short-time-scale data set from an Argentinean field and a large-scale data set from a North Sea field. The simulation results and field applications show that the connectivity between wells is described by model coefficients (weights) that are consistent with known geology, the distance between wells, and their relative positions. The developed procedure provides parameters that explicitly indicate the attenuation and time lag between injector and producer pairs in a field without filtering. The new procedure provides a better insight into the well-to-well connectivities for both fields than the purely resistive model. The new procedure has several additional advantages. Itcan be applied to fields in which wells are shut in frequently or for long periods of time.allows for application to fields in which the rates have a remnant of primary production.has the capability to incorporate bottomhole-pressure (BHP) data (if available) to enhance the investigation about well connectivity. Introduction Production and injection rates are the most abundant data available in any injection project. Valuable and useful information about interwell connectivity can be obtained from the analysis of these data. The information may be used to optimize subsequent oil recovery by changing injection patterns, assignment of priorities in operations, recompletion of wells, and infill drilling. A variety of methods have been used to compare the rate performance of a producing well with that of the surrounding injectors. Heffer et al. (1997) used Spearman rank correlations to relate injector/producer pairs and associated these relations with geomechanics. Refunjol (1996), who also used Spearman analysis to determine preferential-flow trends in a reservoir, related injection wells to their adjacent producers and used time lags to find an extreme coefficient value. De Sant'Anna Pizarro (1998) validated the Spearman rank technique with numerical simulation and pointed out its advantages and limitations. Panda and Chopra (1998) used artificial neural networks to determine the interaction between injector/producer pairs. Soeriawinata and Kelkar (1999), who also used Spearman rank analysis, suggested a statistical approach to relate injection wells and their adjacent producing wells. They applied superposition to introduce concepts of constructive and destructive interference. See also the works of Araque-Martinez (1993) and Barros-Griffiths (1998). Albertoni and Lake (2003) estimated interwell connectivity on the basis of a linear model with coefficients estimated by multiple linear regression (MLR). The linear-model coefficients, or weights, quantitatively indicate the communication between a producer and the injectors in a waterflood. Filters were adopted to account for the time lag between producer and injector. In this work, as in Albertoni and Lake (2003), the reservoir is viewed as a system that converts an input signal (injection) into an output signal (production). However, we use a more complete model that includes capacitance (compressibility) as well as resistive (transmissibility) effects. For each injector/producer pair, two coefficients are determined; one parameter (the weight) quantifies the connectivity, and another (the time constant) quantifies the degree of fluid storage between the wells. This work shows that the new model better captures the true attenuation and time lag between injector and producer pairs. The new procedure resolves several limitations of the previous methods and extends the applications to a wide range of real cases. It can be applied to fields in which wells are shut in frequently or for long periods of time, it allows for application to fields in which the rates have a remnant of primary production, and it has the capability to use BHP data (if available) to enhance the investigation of the well's connectivity.
Proposal This paper presents a new procedure to quantify communication between vertical wells in a reservoir based on fluctuations in production and injection rates.The proposed procedure uses a nonlinear signal processing model to provide information about preferential transmissibility trends and the presence of flow barriers. Previous work used a steady-state (purely resistive) model of interwell communication.Data in that work often had to be filtered to account for compressibility effects and time lags.Even though it was often successful, the filtering required subjective judgment as to the goodness of the interpretation.This work uses a more complicated model that includes capacitance (compressibility) as well as resistive (transmissibility) effects. The procedure was tested on rates obtained from a numerical flow simulator.It was then applied to a short time-scale data set from an Argentinean field and a large-scale data set from a North Sea field.The simulation results and field applications show that the connectivity between wells is described by model coefficients (weights) that are consistent with known geology, the distance between wells and their relative positions.The developed procedure provides parameters that explicitly indicate the attenuation and time lag between injector and producer pairs in a field without filtering.The new procedure provides a better insight into the well-to-well connectivities for both fields than the purely resistive model. The new procedure has several additional advantages.Itcan be applied to fields in which wells are shut-in frequently or for long periods of time,allows for application to fields where the rates have a remnant of primary production, andhas the capability to incorporate bottom hole pressure data (if available) to enhance the investigation about well connectivity. Introduction Production and injection rates are the most abundant data available in any injection project.Valuable and useful information about interwell connectivity can be obtained from the analysis of these data.The information may be used to optimize subsequent oil recovery by changing injection patterns, assignment of priorities in operations, recompletion of wells, and in-fill drilling. A variety of methods have been used to compare the rate performance of a producing well with that of the surrounding injectors.Heffer et al.[1] used Spearman rank correlations to relate injector-producer pairs and associated these relations with geomechanics.Refunjol[2], who also used Spearman analysis to determine preferential flow trends in a reservoir, related injection wells with their adjacent producers and used time lags to find an extreme coefficient value.Sant'Anna Pizarro[3] validated the Spearman rank technique with numerical simulation and pointed out its advantages and limitations.Panda and Chopra[4] used artificial neural networks to determine the interaction between injector-producer pairs.Soeriawinata and Kelkar[5], who also used Spearman rank analysis, suggested a statistical approach to relate injection wells and their adjacent producing wells.They applied superposition to introduce concepts of constructive and destructive interference.See also the works of Araque-Martinez[6] and Barros-Griffiths[7]. Albertoni and Lake8 (hereinafter AL) estimated interwell connectivity based on a linear model with coefficients estimated by multiple linear regression (MLR).The linear model coefficients, or weights, quantitatively indicate the communication between a producer and the injectors in a waterflood.Filters were adopted to account for the time lag between producer and injector.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractAn experimental study of immiscible WAG (water-alternating gas) injection is presented. The target reservoir is the waterflooded Troncoso sandstone in Chihuido de la Sierra Negra Field in Argentina. The original reservoir fluid was an undersaturated light oil with a viscosity of about 1 cp and 13 to 20 mole percent carbon dioxide.Phase behavior tests were conducted using live reservoir oil and synthetic candidate injection gases. They were aimed at assessing the extent to which compositional effects could affect oil recovery at current reservoir pressure.Coreflooding experiments were performed on field core composites using current field production gas which has 65 mole % CO 2 . The samples were initially saturated with live oil and irreducible formation water and then flooded with formation water to residual oil saturation at reservoir conditions. Following waterflood, a number or WAG cycles were injected. The displacements were conducted at pressures well below the estimated minimum miscibility pressure for this system. Tertiary oil recovery efficiency resulting from WAG injection was significant, leading to final residual oil saturations as low as 13 % pore volume (PV). Results of corefloods and compositional laboratory tests suggest that the displacement mechanism is a combination of compositional effects and fluid mechanical effects. The former include interfacial tension reduction, oil swelling and viscosity reduction. Mechanical, fluid distribution effects result from the presence of the free gas phase in the pore system and the cyclic variation in gas and water saturations, as accounted for in a recently developed immiscible WAG phenomenological model that has been used to simulate the process presented here.
The paper presents the experience of a multilateral well campaign for a viscous oil field and its benefits in terms of production. The field is located in the North Slope of Alaska. The production start up was in January 2011. The main hydrocarbon reservoir is a Cretaceous sedimentary series developed in a sand lobe environment within the Schrader Bluff formation. The structure is a monocline gently dipping to NE with a gross thickness of about 30–35 ft. The oil presents different characteristics due to the instauration of a biodegradation process. Oil densities vary between 16°-19° API with associated viscosities in the range of 50–200 cP at reservoir conditions. The crude quality and drill pad constraints (one offshore, one onshore) drove the development concept which consisted of a waterflood linedrive with horizontal producers and water injector wells located side by side. The lateral sections are 6,000′–10,000′ long through the reservoir with undulating counter-phase trajectories across the two main sand bodies. A challenging horizontal reach/depth step-out ratio around 6.5 has been achieved. The completion string was equipped to provide the capability of integrating a complex reservoir monitoring plan including distribute temperature surveys, inflow control devices and polymer tracers. The choice came out from the need of minimizing the cost and mitigating risk with the highest respect for the environment and the local communities. With the goal of increasing reservoir contact, the multilateral concept consisting of undulating counter-phase dual-laterals was tested in August 2013. This initial test was followed by a limited campaign. As a result, well production doubled with respect to the average before the intervention. Similar productivity improvements were also observed in the new producers. At the time production was sustained by 20 producers and 15 injectors. Since then, eight additional laterals were added to existing producers and three new development wells were drilled and completed. The fieldwide step-change was evident with an overall production enhancement around plus 82% in May 2014. After the first encouraging results, the multilateral campaign has been extended to all the producers and is now standard practice for the remaining development wells in this field.
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