No abstract

A new polymer based gel system has been developed to address the excessive water production problem in fractured unconventional gas wells. Currently available polymer based water shut-off agents are unsuitable for treating high temperature hydraulically-fractured tight gas and shale reservoirs, where some fractures connect to water rich zones. The new gel developed is a low-concentration, low-viscosity delayed-crosslink polymeric gel system and is a significant improvement over traditional flowing gels used for fracture water shutoff in conventional reservoirs. The gel uses high molecular weight hydrolyzed polyacrylamide (HPAM) at low concentrations with a delayed organic crosslinker that is more environmentally benign, provides much longer gelation time (up to several days at temperatures well above 100 °C) and stronger final gels than comparable polymer loadings with chromium carboxylate crosslinkers. Results indicate that gelant with a few tens of centipoise viscosity can have gelation delayed to 12 hours or longer at temperatures of 100 °C and higher. Gels prepared with 4000 to 7000 ppm of HPAM and Polyethylenimine (PEI) were significantly stronger than those prepared with the Chromium(III) Acetate crosslinker for the same HPAM concentrations. This new gel system allows low-pressure extrusion of gelant into narrow-aperture fractures. The system is especially promising for deeper, hotter formations where rapid pressure buildup or gel instability prevents the use of current flowing gel systems. The gelant can be pumped with low pressures due to low concentration of polymer and delayed gelation to effectively seal problem water zones thereby reducing operational costs and increasing recovery. By impeding water production, the gel system developed here can be used to delay water loading and subsequent premature abandonment (or installation of expensive equipment), thereby extending life and reserves of unconventional gas wells. Potential applications include the Barnett Shale, where 15 percent of wells produce more water than injected during drilling and stimulation, presumably due to hydraulic fracture growth into underlying water zones.

Complete fluid shutoff using crosslinked polymer gels represents an effective means of water control in reservoirs producing uneconomical volumes of water. To achieve this goal, a new organic crosslinker was developed for complete matrix shut-off in lower temperature reservoirs (80 to 140°F).The system uses a low molecular weight, crosslinked polymer that is injected directly into the target zone, reducing the permeability in the matrix.The crosslinker represents a significant improvement over traditional organic crosslinkers like polyethyleneimine (PEI) and chromium-based metallic systems. The new product has very similar gelation time (<12hr) profiles to the chromium systems, but requires shorter times than PEI, which could have gel times to ~24hr at 80°F. Additionally, the system has a much smaller environmental footprint, easing operator's concern over the sustainability of their chemical shutoff system. Results indicate that the new crosslinker yields ringing gels at lower dosages than traditional organic crosslinkers like PEI.(Sydansk gel code J).This product enables easy generation of ringing, rigid gels for low-temperature reservoirs within a reasonable gelation time (<12hr), making it ideal for applications including water shut-off, casing leak repairs, cement squeeze alternatives, zone abandonments, etc. It represents a cost-effective, environmentally friendly alternative to heavy-metal containing chromium systems where current available organic systems require longer shut-in times and increased concentrations to achieve similar gel strengths. A series of performance tests including laboratory core analysis was conducted to determine it's operating effectiveness. The product was successfully field tested in the Spraberry formation in the Permian basin.

Implementation of video production logging in conjunction with the use of high molecular weight polymer gels, has led to successful water isolation operations in the Fayetteville shale. The dry natural gas field, located in northern Arkansas, is a horizontal play with the wells cased, cemented, and completed with multi-stage slickwater fracture stimulations using perforation and plug technology (Harpel, 2012).Accurate detection of extraneous water entry points along the wellbore is vital for precise water isolation treatment, while still protecting the hydrocarbon producing intervals. Conventional production logging tools have been utilized in the past but proved to be expensive, due to the wellbore configuration, and imprecise because of the horizontal trajectory and debris encountered in the wellbore, with the debris generally rendering the spinner tool inoperable. Video logging tools, deployed in combination with high frequency temperature and pressure gauges, have considerably improved identification of water entries along the wellbore. In addition, the use of a smaller logging assembly has also drastically reduced workover costs by permitting logging through the existing 2-3/8" OD production tubing whereas conventional production logging required the removal of the production tubing due to size limitations. By maintaining this wellbore configuration the flowing conditions remain undisturbed and increase the accuracy of the production log.Based on video production log results the proper water isolation operation is subsequently selected. While cement squeezes and mechanical isolation tools have been applied successfully in horizontal wells to isolate inflow from water producing perforations, they are limited in their applications due to the wellbore configuration and operational costs. Recently, treatment of water producing perforations with chrome (III) carboxylate acrylamide polymer (CC/AP) gel technology has allowed selective treatment in additional sections of the wellbore. These gel treatments have yielded strong results by isolating water production and increasing gas production by reducing the flowing bottomhole pressure. Evaluation and selection of the appropriate polymer gel is discussed along with design considerations and implementation.

The optimistic outlook of the petroleum industry, especially with regard to natural gas, has led to a renewed interest in shale gas plays and more specifically to the Haynesville Shale formation. Through the use of post-stimulation completion diagnostics, insights have been obtained that can be utilized to optimize future hydraulic fracturing completions. This paper will illustrate the use of post-stimulation completion diagnostics in identifying trends that are associated with effective completions in the Haynesville Shale. Case histories will be presented which illustrate methods that have increased the overall completion effectiveness in relation to proppant placement, wellbore deliverability, and ultimately increased production performance. A horizontal well database (&gt; 500 wells) was compiled to identify effective completion trends across the Haynesville Shale formation. By employing proppant and fluid-based tracers, hydraulic fracture characteristics, well deliverability, and ultimately production performance were measured to highlight trends that increased overall completion effectiveness. Primary completion results highlighted areas including, but not limited to, effective proppant placement, full lateral production, frac stage length and containment, perforation cluster spacing, wellbore lateral length, and constrained flowback effects. This paper reviews many of the insights that have been developed through this use of post-stimulation completion diagnostics in the Haynesville Shale formation and which have led to increased completion optimization, production enhancements, and field-wide cost reductions.