Multibranch Injector/Producer Wells in Thick Heavy-Crude Reservoirs

Summary

With modern drilling techniques, it is now possible to drill wells with multiple branches emanating from the same vertical or even horizontal trunk. Several heavy-crude reservoirs are very thick, and low vertical permeability would make them unattractive for single horizontal wells. Further, the much higher viscosity of the reservoir fluid results in highly unfavorable mobility. Thus, drilling stacked horizontal branches would create effectively thinner drainage areas in which the vertical mobility is far more forgiving. However, the clear benefit derived from thermal recovery favors steam injection and invites investigation of ways to improve on the Steam Assisted Gravity Drive (SAGD) application.

As an extension of the SAGD concept, this paper uses thermal reservoir simulation to investigate the effects of increasing the spacing between the injector and producer, or adding producers above or below the SAGD configuration, to mine more of the heat transferred to the reservoir by the injected steam. Simulations are performed with the Eclipse 500 thermal simulator using reservoir and fluid properties typical of the Bachaquero field in Venezuela. Economics confirm the merits of the approach.

Introduction

Frequently, highly viscous petroleum (heavy crude) is found in relatively shallow reservoirs often characterized by thick, loosely consolidated or unconsolidated rocks. The Orinoco belt in Venezuela is an example of a thick heavy-oil column. Horizontal permeability is frequently as high as 10 darcies or more, but the crude-oil viscosity is also high, frequently exceeding 10,000 cp. The resultant mobility, k/µ=1 md/cp, is sufficiently low that conventional production from vertical wells is at best marginally economic. By way of comparison, deeper reservoirs with lighter oil frequently have mobilities exceeding 100 md/cp or more.

Often, the optimal well trajectory in a thick reservoir is a vertical well because productivity is a function of mobility thickness. Horizontal wells offer significant productivity improvement in thin reservoirs, but in thick reservoirs the productivity boost from a horizontal well requires a favorable vertical permeability (Joshi et al.¹ and Economides et al.²). However, low vertical permeability may be beneficial when horizontal wells are employed as a strategy to mitigate gas or water coning in thick reservoirs overlain by a gas cap or underlain by water.

Economic success in heavy-oil production has been found both by cold production^3-7 and by steam injection^8-11 with both vertical and horizontal well strategies.

The emergence of complex well architecture provides a potentially highly attractive configuration where a multilevel/multibranched scheme can be constructed. This paper focuses on the configurations of stacked parallel laterals, shown in Fig. 1. Case studies placing the steam injector above the producer (as in SAGD) or below (inverted SAGD) are considered. Examination of the vertical temperature profiles for various lateral configurations shows that excess heat can be mined to increase both the production rate and the ultimate recovery. A practice that is worth mentioning is the engineering of a completion that enables both production and injection in the same wellbore with annular flow of the produced oil in the casing and steam injected in the tubing (Single Well SAGD).¹²

Cold Production

Historically, heavy-oil production was possible mainly because the shallow reservoirs could be drilled inexpensively with vertical wells, and even low production rates would pay for the wells. Before horizontal-well drilling became common, the main way to enhance heavy-oil production was with steam injection, either cyclically (huff ‘n' puff) or continuously in injection and production well patterns with very closely spaced vertical wells.

In the last few years, three other mechanisms have been introduced that have improved production without steam or hot-water injection enough that the term cold production is now in common use. First, horizontal wells provide a means for well-productivity increases ranging from an average of 3 times to as much as a 10-fold improvement over vertical wells. Usually, the incremental cost of the horizontal well over a vertical well is much less than 50%.

A second cold-production technique is the use of submersible pumps that drop the pressure enough to induce a special flow mechanism called foamy-oil production.^3,4 The rates achieved under foamy-oil production are often much greater than would be predicted by classical Darcy's Law estimates. Apparently, foamy-oil production results when gas comes out of solution in the reservoir and remains entrained as a foam phase. Foamy-oil production does not always occur and is a function of the heavy-oil composition.

A third cold production process is to use PDP (Positive Displacement Pump) or screw pumps that allow sand production with the oil.^5-7 With as much as 30% by volume sand production, oil-production rates may increase over time by factors of as much as 20 times. The explanation offered for this remarkable productivity increase is the formation of wormholes, a phenomenon in which the produced sand leaves behind tunnels near the producing well. This has the effect of continually increasing the effective well radius.

The cold-production simulations in this study are intended to improve on the horizontal-well strategy with additional stacked horizontal branches.

Single-Level Cold Production.

The single-lateral cold-production case is diagramed in Fig. 1a. Simulations conducted for this and the other cases featured in this work used the same fluid and rock properties as were used for the simulations in Ref. 10. These are listed in Table 1. All the simulations are conducted in a closed rectangular reservoir drainage volume with no natural pressure support. Figs. 2 and 3 show dependence of relative permeability on saturation and of oil viscosity on temperature. All simulations were conducted at constant steam-injection rates. The injection pressure was adjusted by the model to maintain the constant injection rate, and injection temperature was automatically the saturation temperature for the injection pressure.

Single-Level Cold Production.

The single-lateral cold-production case is diagramed in Fig. 1a. Simulations conducted for this and the other cases featured in this work used the same fluid and rock properties as were used for the simulations in Ref. 10. These are listed in Table 1. All the simulations are conducted in a closed rectangular reservoir drainage volume with no natural pressure support. Figs. 2 and 3 show dependence of relative permeability on saturation and of oil viscosity on temperature. All simulations were conducted at constant steam-injection rates. The injection pressure was adjusted by the model to maintain the constant injection rate, and injection temperature was automatically the saturation temperature for the injection pressure.