Effectively stimulating multiple pay zones using separate fracturing treatments can be costly and time consuming. By contrast, multistage fracturing is a widely used technique that offers the advantage of stimulating significant portions of the reservoir by fracturing through multiple perforations simultaneously. While the multistage fracturing method known as "plug and perf" has been proven to be an effective method for developing unconventional resources, it presents the challenge of achieving even proppant distribution to all perforation clusters during each stimulation stage.It is commonly assumed that the plug and perforate multistage fracturing technique provides the planned fluid and proppant distribution among the fractures that are simultaneously taking fluid during pumping a single stage. However, parameters, such as the reservoir properties, fluid rheology, and proppant characteristics have demonstrated a strong influence on the actual proppant and fluid distribution into the various perforations.Field data indicates, in many cases, that some of the clusters do not contribute to production. This indication supports the hypothesis that actual proppant and fluid distribution along the stimulated clusters might be different from the assumed uniform distribution. Some believe that the amount of proppant appears to be heavily weighted toward the end of the perforated interval, which results in uneven proppant distribution. Empirical data as well as laboratory tests have yet to be challenged against the few studies that exist. This paper presents a first-of-its-kind large-scale investigation that was conducted to study proppant distribution among separated perforations along a horizontal interval. These experiments closely simulate any single stage during the plug-andperforate fracturing process. The effect of various fluid specific gravities, fluid viscosities, proppant specific gravities, proppant sizes, and slurry flow rates were investigated while keeping outside-casing parameters constant. The various aspects of proppant and fluid flow through a perforated interval are discussed. The experimental efforts discussed in this paper create a better understanding of fluid and proppant behavior in this widely used fracturing process to help achieve maximum efficiency.

Use of crosslinked polymer gels employing polymeric base materials and crosslinkers for shutting off water production in a variety of situations has been amply documented at formation temperatures ranging from ambient to > 400°F. However, there has not been much work reported on chemical systems that can provide adequate gel times and gel strengths at temperatures less than 80°F. The reaction rates and gel-strength-development rates are significantly lower at low temperatures, resulting in long gel times and weaker gels. Additionally, in offshore applications, the gelling compositions must be designed to be mixable without crosslinking at warmer surface temperatures, and yet provide sufficient gel times at temperatures as low as 40 to 50°F near the ocean floor, for example, in shallow water/gas zones. Similar limitations might exist in areas known to contain gas hydrates. In this paper, a recently developed water-shutoff system designed from polyacrylamide base polymers and polyamine crosslinkers, which provide sufficient gel times at temperatures less than 80°F, is presented. Challenges encountered in designing such a system included optimizing base polymer to crosslinker ratios and gel-strength-development rates. This paper describes optimization of gel times for the intended applications using activator chemicals and retarders, which allow designing gelling compositions that provide adequate gel times at subambient temperatures while permitting mixing at warmer surface temperatures. The activator and retarder systems also allow control of the development of rigid gels at different crosslinker concentrations. Several practical issues and considerations for designing conformance treatments at low and ultralow temperatures are discussed. Improved temperature modeling and laboratory-testing designed to simulate the fluid-temperature profile during the operation from the wellhead to the formation bottom are also addressed.

Summary Surge and swab pressures have been known to cause formation fracture, lost circulation, and well-control problems. Accurate prediction of these pressures is crucially important in estimating the maximum tripping speeds to keep the wellbore pressure within specified limits of the pore and fracture pressures. It also plays a major role in running casings, particularly with narrow annular clearances. Existing surge/swab models are based on Bingham plastic (BP) and power-law (PL) fluid rheology models. However, in most cases, these models cannot adequately describe the flow behavior of drilling fluids. This paper presents a new steady-state model that can account for fluid and formation compressibility and pipe elasticity. For the closed-ended pipe, the model is cast into a simplified model to predict pressure surge in a more convenient way. The steady-state laminar-flow equation is solved for narrow slot geometry to approximate the flow in a concentric annulus with inner-pipe axial movement considering yield-PL (YPL) fluid. The YPL rheology model is usually preferred because it provides a better description of the flow behavior of most drilling fluids. The analytical solution yields accurate predictions, though not in convenient forms. Thus, a numerical scheme has been developed to obtain the solutions. After conducting an extensive parametric study, regression techniques were applied primarily to develop a simplified model (i.e., dimensionless correlation). The performance of the correlation has been tested by use of field and laboratory measurements. Comparisons of the model predictions with the measurements showed a satisfactory agreement. In most cases, the model makes better predictions in terms of closeness to the measurements because of the application of a more realistic rheology model. The correlation and model are useful for slimhole, deepwater, and extended-reach drilling applications.

Organically crosslinked polymer systems have experienced considerable commercial success in shutting off undesirable water production. One of the systems most widely used to date employs acrylamide-containing polymers as base polymers and polyamines as crosslinkers. Its success can be attributed to 1) low viscosity in a noncrosslinked state, 2) versatility and stability over a wide temperature range, 3) rigid ("ringing") gel formation, and 4) deep matrix penetration. The objective of the present study was to improve the current acrylamide- and amine-based polymer formulations by significantly reducing the polymer concentrations while retaining the gel performance. This was accomplished by the inclusion of organic activators that substantially increase the crosslinking reactivity of the polyamine, allowing reduction in the polymer loading necessary to achieve desired gel times at a specific temperature. The activator materials included alkanolamines and quaternary ammonium salts. An increase in base polymer molecular weight also allowed for significant reduction in base polymer concentrations (to ≤ 1%). While this results in a lower cost system, and is more environmentally acceptable, the change in the quality of the gel from a stiff to a highly deformable type can result in the decreased ability of the gel to resist pressure. Bimodal molecular weight distribution is presented as an alternative approach to decrease polymer loading. This technique consists of the addition of variable amounts of high-molecular-weight base polymer to a constant concentration of low-molecular-weight base polymer. The newly developed formulations, in some cases, allowed for a reduction of up to 40% of base polymer concentration. Results from gel time measurements over a wide temperature range using different base polymers, crosslinker polymers, and potential activation mechanism(s) are discussed.

Surge and swab pressures generated during well construction operations are critical. As thousands of wells are drilled every year, challenges associated with downhole pressure management have become more important for the oil industry. Inadequate estimation of surge and swab pressures can lead to a number of costly drilling problems such as lost circulation due to formation fracture, fluid influx resulting in kicks, breakdown of the formation at shoe due to limited kick tolerance or blowouts. An accurate surge pressure model is very important in planning drilling operations, mainly in wells with narrow safe pressure window, slimholes, low-clearance casings, deepwater, and extended-reach well applications.Existing surge/swab pressure models assume concentric wellbore. This assumption is hardly ever valid in horizontal and inclined wells with some degree of eccentricity. Ignoring the pressure reducing effect of eccentricity on surge and swab pressures may eventually lead to underestimating the tripping speeds, and thereby increase non-productive time and operation costs. Eccentricity between the wellbore and the drillpipe adds more complexity to surge and swab pressure calculations. Recent studies have indicated that surge pressure can be significantly reduced due to eccentricity. Although the numerical investigation shows encouraging results, understanding of pressure surges in wells with eccentric annular geometry is very limited.This paper presents the results of experimental investigations conducted to study the effects of eccentricity on surge and swab pressures. Experiments were performed in a test setup, which consists of fully transparent polycarbonate tubing, and inner pipe that moves axially using a speed controlled hoisting system. During the experiments, test fluid viscosity, trip speed, and eccentricity were varied. Experimental results were compared with predictions of existing models showing a satisfactory agreement. Results confirm that trip speed, fluid rheological properties, annular clearance and eccentricity significantly affect the surge pressure. In some cases, eccentricity can reduce surge and swab pressure by around 40%. Applying regression analysis, a generalized correlation has been developed to account for the reduction in surge pressure due to the eccentricity of the drillpipe.