A number of solvent-based processes for the recovery of heavy oil have been proposed in recent years. One of the phenomena that characterizes all such processes, to varying degrees, is viscous fingering. This paper describes the results of a combined experimental/simulation study aimed at characterizing viscous fingering under conditions typical of heavy oil recovery (very high ratios of oil to solvent viscosity). The study also sheds light on other phenomena that are part of such processes. We describe a set of four experiments carried out in heavy oil saturated sand packs contained within a 30 cm x?60 cm x?1.4 cm visual cell. Three of the experiments involved injection of a miscible, liquid solvent at the bottom of the sand pack, with subsequent upward displacement of the heavy oil; the fourth involved top-down injection of a gaseous solvent. The miscible liquid displacements were dominated by a single solvent finger, which broke through quickly to a producing well at the other end of the sand pack. Observed breakthrough times were consistent with a correlation that describes reported results at lower viscosity contrast. The gaseous solvent experiment exhibited fingering but also had features of a gravity-driven VAPEX process in its later stages. Numerical simulations using a commercial reservoir simulator have been successful in reproducing key features of the experiments. Realistic fingering patterns are produced in the simulations by assuming small, random spatial variations of permeability. The correct modelling of dispersion is crucial in matching the observed phenomena. For gaseous fingering and VAPEX processes, capillary effects are significant and should be included in simulations. Introduction Solvent-based processes for the recovery of heavy oil have attracted increasing attention in recent years. Much of this attention has focused on the Vapour Extraction or "VAPEX" process(1), a solvent analogue of steam assisted gravity drainage (SAGD). However, it has been suggested that for thin reservoirs, and particularly primary-depleted reservoirs, a cyclic solvent process might be preferred. Whereas VAPEX is analogous to SAGD, a cyclic solvent process would be analogous to the cyclic steam stimulation process. A concept for a cyclic process is shown in Figure 1. In this concept, solvent would be injected for a period of time, then oil produced from the same well; and this process would be repeated. A number of questions may be asked about the basic mechanisms of a cyclic solvent process and the resulting efficiency of oil recovery. The work reported here was aimed particularly at understanding the phenomenon of viscous fingering, which characterizes any such process in which a low viscosity solvent is injected into a high viscosity oil. Viscous fingering is an instability phenomenon which occurs when one fluid is displaced by another fluid of lower viscosity. The displacing fluid is said to "finger" into the resident fluid. The two fluids may be either miscible or immiscible, and the displacement may take place in a porous medium or even a Hele- Shaw cell(2, 3).

This paper discusses a relatively new acid-stimulation process that uses dynamic fluid energy to divert flow into a specific fracture point in the well that can initiate and accurately place a hydraulic fracture. These acid-stimulation methods often use two independent fluid streams: the acid phase down the treating string and other liquids or gases down the annulus. The annular fluid may simply serve as a wellbore pressurizing component, or with this process, two different fluids can be mixed downhole with high energy to form a homogenous mixture. Using variations of this process, treatments were performed in four openhole, horizontal wells in the same formation. The first well was acid-fractured with coiled tubing to place many small fractures along the open hole. The second well was acidfractured with coiled tubing, but downhole mixing concepts were also used to provide in-situ generation of CO2 foam where fewer, but larger, fractures were placed in this well. The third and fourth wells were treated with acid using blasting-type rotating or non-rotating jetting tools while mixing the acid with CO2 downhole. Numerous small, near-wellbore fractures were the expected result in these two wells. Experimental laboratory investigation of the physical mechanisms that contributed to these successful stimulations was considered important. Large-scale laboratory tests were performed to more closely examine the physical rock response to the jetting mechanism and conditions. The findings of these tests are presented in this paper. Introduction In an openhole lateral, successful production enhancement treatment depends on identifying the causes of the production deficiency for the specific well to be treated, properly understanding the remedial treatment options available, and evaluating the economics of available options. Assuming the problem is not inadequate reservoir size or recoverable reserves, production deficiencies can result from many factors in a horizontal openhole completion, including: wellbore debris, filter cake or other near-wellbore damage, deeper permeability damage, low formation permeability, or even wellbore location within the reservoir. If the production problem is caused by debris plugging along the lateral, the well can usually be cleaned with an effective hydrablasting and cleaning process. This service generally combines specialized fluid systems (often foams) and possibly a wash tool designed for the different mechanics associated with cleaning deviated or horizontal wellbores. Some processes incorporate computerized design software to properly plan the clean-out operation. If a solids filter-cake has caused near-wellbore damage that is responsible for the production deficiency, an acid wash might be the best solution. Coiled tubing (CT) applications can often allow more efficient washing of the entire lateral or of specific preselected zones. Using tools with jetting nozzles can enhance the effectiveness of acid washes, or even nonreactive fluids that provide the benefits of only mechanical-jetting effects. If deeper damage in the near-wellbore region is decreasing production, an operator may desire to place several small hydraulic fractures at many places along the lateral section to bypass the damage. Such small fractures can use relatively small volumes of acid to give a beneficial result similar to increasing the wellbore diameter, and do so without problems associated with excessive hole enlargement. If the wellbore is located in a poorly producing zone in the reservoir some reasonable distance from a better part of the reservoir, or if a vertical permeability barrier exists, the operator may need to create larger fractures that can communicate the wellbore with more productive zones.

Hydrajet perforating and fracturing has recently gained popularity in the oilfield industry, especially when used with coiled tubing (CT). With coiled tubing, the task of placing many cuts at multiple places becomes straightforward and no longer time consuming. However, hydrajetting equipment life has been plagued with rapid failures, resulting in the need for time-consuming and costly tripping out and in the hole for jetting tool replacement. To reduce or eliminate such tripping costs, substantial improvements of the hydrajetting tools are required. A mere change of materials or a redesign using concepts that follow the customary models has resulted in insignificant performance improvements. It was therefore decided that a complete overhaul of the design concepts needed to be made. By doing this, substantial improvements can be obtained. This paper discusses unique improvements that have been made to the hydrajetting tools. The new tools address the aspects that have contributed to failures in the past. By taking a fresh perspective of this situation, a performance improvement of 200-300% can be attained. Recent perforating and stimulation experiences in the field demonstrate this and are discussed. Introduction Hydrajetting technology has been in use in various industries since the early 1960s (Summers 1995). From cleaning applications, such as vehicle cleaning or pipeline deposits removal to cutting applications such as cutting steel plate in fabrication or cutting rock slabs in quarries, the hydrajet tool has progressed from a simple tool for removing debris to a tool with tremendous power and accuracy. The tool has advanced from a simple tool with holes to a tool with carbide inserts or even eductors for injecting abrasives into its high-pressure fluid streams. In the oil industry, hydrajetting has been prevalent in scale removal, offshore wellhead removal, and decommissioning of offshore rig platforms. The use of hydrajet equipment also has been very successful in removing burning wellheads in war-torn areas of the Middle East. Success has also been demonstrated in perforating for well production and stimulation (Surjaatmadja, Abass, and Brumley 1994; Surjaatmadja 1993), and lately, for the stimulating process itself (Surjaatmadja et al. 2003; Rodriguez et al. 2005; McDaniel et al. 2004; Surjaatmadja et al. 2005; McDaniel et al. 2006; Surjaatmadja 2007). Because hydrajet cutting employs the use of abrasives, its life is generally limited. In surface or near-surface applications, this factor has been an acceptable risk because regular jet replacements are simple and generally not costly. In deep wellbores however, the primary expense of replacement lies in the cost of tripping, which is time-consuming and therefore expensive. Excessive tripping in and out of the hole to perform tasks is less desirable, yet often acceptable in the oil field today. However, the increased use of hydrajetting in a competitive market for stimulating and perforating, combined with increasing rig costs, has created a situation in which finding ways to reduce costs has become essential. Improving the strength of the jets has demonstrated excellent results, but efforts to continually improve the tools using conventional means may have reached a plateau (high but nowhere else to go). A totally new, patent pending concept is therefore being introduced to both improve the performance and life of jetting equipment in the oil industry.

Like any other business, return on investment (ROI) drives the decision-making processes in the oilfield. The "cut-cost" approach can only be successful when resulting production is adequate. Especially during the past few years, it has been observed that most North America operators using horizontal completions in low-perm oil or gas reservoirs have abandoned the "lowest-cost" approach in favor of a "maximize-production" mindset. Maximizing ROI requires operators to continually evaluate both cost and effectiveness of various completion and stimulation options. With low- to ultralow-perm reservoirs, it has been proven in many fields in North America that using a long lateral section combined with effective, controlled placement of large, multistage propped fracturing treatments can offer the best economic return. Often being combined with pad drilling, the trend continues to be using fewer wells while maximizing the volume of reservoir rock that is fracture stimulated within each completion. There are two interrelated choices that can be combined in several ways to decide how best to complete a lateral section to achieve maximum benefit:Assuming a solid liner is installed, should the operator cement, seal off the annulus into sections by some method, or leave it unsealed?What method should be used to provide frac-stage isolation within the liner? This paper will provide an overview of several different horizontal completion methods and stimulation techniques most commonly used in North America for low-perm reservoirs during the past few years. Included are two different operators' experiences with multiple application methods, but the common denominator is that they included multiwell overviews. Managing risk properly will usually be more than a "current-well" mentality and requires a more field-wide approach, including the cost of completion interruptions from unscheduled/unexpected events. One case takes the comparisons through completion cost and all the way to ROI results, where all wells had more than six months of production. Another case illustrates a situation where the operator concluded that well production is more dependent on reservoir quality than on his choice for completion methods. This case includes more than 75 wells with six to nine fractured intervals per well, comparing not only costs for four methods, but also showing the representative cost variations or overruns. Generally, once a drillsite has been chosen, the most important variable that can be affected is effectively placing individual hydraulic fractures at (and only at) preselected locations along the completed lateral section. Choosing the method to be used is best made before drilling the well, but might have to be revisited if formation properties are different than anticipated or drilling problems result in a wellbore the is a poor fit for the completion plan originally selected. Obtaining effective isolation of stimulation stages is often the primary goal required to achieving adequate production response and effective reservoir exploitation while managing the costs to achieve best ROI on a field-wide basis.

Production from carbonate wells is often controlled by the degree of stratigraphic interconnectivity or lack thereof. Formation stratigraphy results in severely compartmentalized reservoirs. Effective methods for achieving hydraulic interconnectivity with such compartments are limited in horizontal openhole and long pay section in deviated wells. A new technology is emerging that incorporates solid acid capsules that function as both a fluid-diverting agent and a fracture conductivity enhancer. The degradable sized particulate system is incorporated into the acidizing fluid designed to enhance inflow from natural fracture swarms and to help enable propagation of hydraulic fractures that can breach or achieve wellbore communication with the stratigraphic compartments. This paper presents a case experimental project that involves a Canadian carbonate gas reservoir. Historically, horizontal wells drilled in low-permeability reservoirs with no natural fractures have shown poor production response. This successful production stimulation case demonstrates the potential to overcome the compartmentalization problem. In one of the first-use case wells reviewed in this paper, up to a 10-fold increase in reservoir pressure was observed in a short-term buildup test, and the well was converted into an economic producer. Image logs were used to provide location and distribution of mineralized natural fracture swarms targeted for stimulation. Production data, laboratory data and post-treatment productivity index (PI) are presented. This paper adds to the industry's technical knowledge base by:offering a practical, lower cost, high value solution to a significant emerging market;documenting the first use of a new technology application;presenting evidence of the technology's widespread global application to carbonate reservoirs and possibly sandstone reservoirs. Introduction Effective stimulation or production enhancement of long, openhole, horizontal, and deviated (directional) completions in reservoirs composed of multiple thrust sheets carbonate zones have been a long-standing challenge to operators. Numerous techniques have been attempted with varying degrees of technical and economic success.1–11 To develop effective solutions, the reservoir and geologic controls that constrain the technical solution should be described first. Carbonate reservoirs are heterogeneous by nature, especially in the context of distribution of natural fracture systems known as fracture swarms.12–15 Both horizontal and deviated wells are often drilled with the intent of intersecting as many natural fracture networks (swarms) as economically feasible. Often, predicting ahead of the bit the exact location and distribution of the natural fracture swarms that control production potential or reservoir access can be difficult or impractical. Further, performing diagnostic log evaluations on the horizontal sections after the well is drilled can be cost-prohibitive. After the drilling process, specific geologic information often is not known, such as specific distribution or location; whether the natural fractures are open, healed, or partially open, or damaged; and depth of reservoir access from the natural fracture conduits. Normally, in such tight, dual-porosity systems, performing extensive hydraulic fracturing treatments over such long intervals has a limited success and is cost-prohibitive, and if natural fracture swarms are absent where the hydraulic fractures are placed, the well likely will not meet economic expectations. The technical challenge presented and discussed in this paper involves the novel application of acidizing-encapsulated acid diversion designed to enhance reservoir communication with the wellbore using existing natural fracture conduits that are presumed to be open, partially healed, or mineralized.