Conformance problems often exist in natural gas-related activities, resulting in excessive water production from natural gas production wells and/or excessive natural gas production from oil production wells. Several mechanical and chemical solutions were reported in the literature to mitigate the conformance problems. Among the chemical solutions, two classes of materials, namely polymer gels and water-soluble polymers, have been mostly reported. These systems have been mainly reviewed in several studies for their applications as water shutoff treatments for oil production wells. Natural gas production wells exhibit different characteristics and have different properties which could impact the performance of the chemical solutions. However, there has not been any work done on reviewing the applications of these systems for the challenging natural gas-related shutoff treatments. This study provides a comprehensive review of the laboratory evaluation and field applications of these systems used for water control in natural gas production wells and gas shutoff in oil production wells, respectively. The first part of the paper reviews the in-situ polymer gel systems, where both organically and inorganically crosslinked systems are discussed. The second part presents the water-soluble polymers with a focus on their disproportionate permeability reduction feature for controlling water in gas production wells. The review paper provides insights into the reservoir conditions, treatment design and intervention, and the success rate of the systems applied. Furthermore, the outcomes of the paper will provide knowledge regarding the limitations of the existing technologies, current challenges, and potential paths forwards.
Summary One of the most prevalent, expensive, and time-consuming problems during drilling operations is the loss of circulation. Uncontrolled lost circulation of drilling fluids may lead to dangerous well control difficulties and, in some cases, complete loss of the well. In this paper, the ability of a low-temperature recrosslinkable preformed particle gel (LT-RPPG) has been evaluated to determine the extent to which it can be used to control drilling fluid losses during drilling operations. The RPPG consists of swellable gel particles that can self-crosslink to form a strong bulk gel in fractures to form strong plugging after being placed in the loss zones. We investigated the effect of the LT-RPPG swelling ratio and fracture width on its plugging efficiency to fractures through core flooding tests. Results showed that its sealing pressure can reach up to 1,381 psi/ft and permeability reduction more than 99.99% when the RPPG swelling ratio is five for the fracture with a width of 2.00 mm. LT-RPPG is a good candidate that can be used to control the severe or total loss during drilling operations.
Summary Preformed particle gels (PPGs) are 3D, crosslinked, dried polymer particles that can swell to several hundred times on contact with formation water. PPGs have been used extensively to control water production problems in reservoirs with conformance problems. The current state-of-the-art PPGs are polyacrylamide-based hydrogel compositions which lack long-term thermal stability under high-temperature and -salinity conditions. There are many oil reservoirs across the globe exhibiting conditions of temperatures higher than 120°C with high salinity. A novel ultrahigh-temperature-resistant PPG composition (DMA-SSS PPG) was designed to fill up the technology gap between existing polyacrylamide-based PPG technology that degrades readily over 110°C temperatures. DMA-SSS PPG exhibited excellent thermal stability for greater than 18 months in North Sea formation and formation water environments at 130°C. DMA-SSS PPG described herein showed swelling capacities of up to 30 times in different salinity North Sea brines. DMA-SSS PPG’s physiochemical properties like swelling, swelling rate, and rheological behavior were studied as a function of temperature and salinity. DMA-SSS PPGs showed excellent elastic modulus (G’) of about 3200 Pa in formation water of 90% water content. Thermostability of DMA-SSS PPGs was assessed at 130 and 150°C in North Sea brines with different salinity conditions. DMA-SSS PPGs proved to be stable for more than 18 months without losing molecular integrity. Thermostability was further confirmed through different metrics such as cross-polarization magic angle spinning carbon-13 nuclear magnetic resonance (CPMAS 13C NMR), thermogravimetric analysis (TGA), and morphology. Laboratory coreflood experiments were performed to demonstrate the plugging efficiency of open fractures and effectiveness in reducing the permeability. DMA-SSS PPG comprehensive evaluation confirms its novelty for excellent hydrothermal stability, thus can be used to control water production problems for mature reservoirs exhibiting conditions of high salinity and high temperature.
Millimeter-sized superabsorbent polymers (SAPs), also called preformed particle gels (PPGs), are gaining attention and popularity for use in conformance-improvement treatments. The strength of PPGs is important to the optimization of their performance as plugging agents. Conventional gel strength has always been measured by applying load to single, isolated sample with certain geometry. However, determining the strength of sugar-like PPGs with irregular shapes is a challenging task. Previous publications have proposed different methods to evaluate gel strength. However, those methods are not suitable for rapid quantitative evaluation of PPG strength on site. We designed a simplified experimental apparatus to evaluate gel strength in the laboratory or on site during gel treatment. It consists of a positive displacement hand pump and a specially designed piston accumulator. The top cap of the accumulator has a hole connected to the pump by tubing and fittings. The bottom cap is a stainless steel screen plate with multiple holes. During the experiments, we placed swollen PPG on top of the screen plate and below the piston, gradually increasing the pressure to push the piston until gel particles passed through the plate holes. The minimum pressure needed to push gel particles out of the holes was considered as the threshold pressure of a gel particle moving through a pore throat, which provides quantitative indication of the gel strength. The apparatus also can be used to evaluate gel rheology in terms of its apparent viscosity as a function of the shear rate. We observed that the PPGs are prone to stiffen as the brine salinity increased which caused the threshold pressure to increase. Also the PPGs threshold pressure depended chiefly on the brine salinity, the screen hole size, and the holes density per screen plate. Additionally, the PPGs threshold pressure correlated excellently with their elastic modulus which was measured using a rheometer. PPGs injection pressure did not increase significantly with the injection rate. This behavior is consistent with the real-time injection pressure and injection rate change which has been often observed during PPG treatments in oilfields. This method can serve as a simple, fast, and practical technique to quantitatively evaluate particle gel strength in the laboratory and on site during a PPG treatment process.
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