Reservoir Densification, Pressure Evolution, and Natural Gas Accumulation in the Upper Paleozoic Tight Sandstones in the North Ordos Basin, China

The Dongsheng gas field is a water-bearing tight gas reservoir characterized by high connate water saturation. During gas production, the transformation of connate water into movable water introduces a unique water production mode, significantly impacting gas reservoir recovery. Current experimental and theoretical methods for assessing formation water mobility are static and do not address the transformation mechanism from connate into movable water. In this study, we considered dynamic changes in formation stress and proposed the mechanism for the transformation of connate water into movable water during depressurization, involving the expansion of connate water films and the reduction of pore volume. We developed a novel methodology to calculate the dynamic changes in movable and connate water saturation in tight reservoirs due to reservoir pressure reduction. Furthermore, we quantitatively evaluated the transformation of connate water into movable water in the Dongsheng gas field through laboratory experiments (including formation water expansion tests, connate water tests, and porosity stress sensitivity tests) and theoretical calculations. Results show that under original stress, the initial connate water saturation in the Dongsheng gas field ranges from 50.09% to 58.5%. As reservoir pressure decreases, the maximum increase in movable water saturation ranges from 6.1% to 8.4% due to the transformation of connate water into movable water. This explains why formation water is produced in large quantities during gas production. Therefore, considering the transition of connate water to movable water is crucial when evaluating water production risk. These findings offer valuable guidance for selecting optimal well locations and development layers to reduce reservoir water production risks.

Section: Introductionmentioning

confidence: 99%

“…During gas reservoir development, most gas wells initially experience minimal water production. However, as reservoir pressure decreases, some wells transition to water production [13,18,19]. As a result, fluid flow shifts from gas-phase flow to a gas-water two-phase flow within tight reservoirs, increasing flow resistance.…”

Section: Introductionmentioning

confidence: 99%

Research on Transformation of Connate Water to Movable Water in Water-Bearing Tight Gas Reservoirs

Chen,

Wang,

et al. 2023

“…For example, of the unconventional natural gas production in 2022, tight sandstone gas ranked first in China and second only to shale gas in North America. Current exploration and development experience shows that the "sweet spot" of a gas reservoir and its development mode are two key factors affecting the production of tight sandstone gas reservoirs [2][3][4][5]. Gas flow/migration dynamics and the gas-water distribution pattern in tight sandstone gas reservoirs not only control the formation and distribution of high-yield "sweet spots" but also are the important geological basis for selecting efficient development modes and deploying drilling campaigns [4][5][6][7][8].…”

Section: Introductionmentioning

confidence: 99%

Driving Forces of Natural Gas Flow and Gas–Water Distribution Patterns in Tight Gas Reservoirs: A Case Study of NX Gas Field in the Offshore Xihu Depression, East China

He,

Li,

Duan

et al. 2023

The driving forces behind gas flow and migration, as well as the associated gas–water distribution patterns in tight gas reservoirs, are not only closely related to the formation mechanisms of “sweet spots”, but also serve as crucial geological foundations for the development of efficient modes and optimal well placement. In this work, three methods, namely, critical gas column height driven by buoyancy, critical pore throat radius driven by buoyancy, and gas–water distribution attitude, were used to quantitatively evaluate the critical conditions for buoyancy and overpressure to get gas flowing in the tight sandstone gas field. In light of the geological background, the driving forces of gas flow/migration and gas–water distribution patterns were comprehensively analyzed. On this basis of the origins of overpressure driving gas flow/migration were identified by using multiple empirical methods, the evolution of overpressure and characteristics of gas–water distribution driven by overpressure were studied by using PetroMod_2014 simulation software. The results show that the four main gas-bearing layers in the NX tight sandstone gas reservoir differ widely in gas flow/migration dynamics and gas–water distribution patterns. Gas accumulation in the H3b layer is influenced by both buoyancy and overpressure. Subsequently, buoyancy leads to the differentiation of gas from water based on density and the formation of edge water. Furthermore, the distribution area of the gas reservoir is determined by the presence of an anticline trap. In contrast, in H3a, H4b and H5a gas layers, buoyancy is not sufficient to overcome the capillary force to make the gas migrate during and after accumulation, and the driving force of gas flow is the overpressure formed by fluid volume expansion during hydrocarbon generation of Pinghu Formation source rocks. Because buoyancy is not the driving force of natural gas flow, H3a, H4b and H5a layers have gas and water in the same layer and produced together, and no boundary and bottom water, where the anticlinal trap does not control the distribution of gas and water, and gas source faults control the boundary of the gas reservoir. These understandings not only significantly expand the gas-bearing target of H3a, H4b and H5a gas layers delineated in the buoyancy driving pattern but also provide an important geological basis for the formulation of an efficient development plan by class and grade for the NX tight sandstone gas field.

“…However, most unconventional reservoirs are not presented in a single mode but, rather, often in a mixed mode of unconventional and conventional reservoirs. For example, there are various reservoirs, traps, and hydrocarbon accumulation mechanisms in the Sichuan Basin and the Ordos Basin, but there are several models of hydrocarbon accumulation [4][5][6][7]. A single mode cannot meet the current need for hydrocarbon exploration and development [8,9].…”

Section: Introductionmentioning

confidence: 99%

Multi-Type Hydrocarbon Accumulation Mechanism in the Hari Sag, Yingen Ejinaqi Basin, China

Peng

Zhang

et al. 2022

With the successful development of unconventional hydrocarbons, the production of unconventional hydrocarbons has increased rapidly. However, a single conventional or unconventional model is not suitable for the mechanism of hydrocarbon accumulation in a given basin or sag. Based on data from drilling, logging, and geophysical analysis, the hydrocarbon accumulation mechanism in the Hari sag in the Yingen-Ejinaqi basin, China, was analyzed. There are three sets of source rocks in the Hari sag: the K1y source rocks were evaluated as having excellent source rock potential with low thermal maturity and kerogen Type I-II1; the K1b2 source rocks were evaluated as having good source rock potential with mature to highly mature stages and kerogen Type II1-II2; and the K1b1 source rocks were evaluated as having moderate source rock potential with mature to highly mature stages and kerogen Type II1-II2. Reservoir types were found to be conventional sand reservoirs, unconventional carbonate-shale reservoirs, and volcanic rock reservoirs. There were two sets of fault-lithologic traps in the Hari sag, which conform to the intra-source continuous hydrocarbon accumulation model and the approaching-source discontinuous hydrocarbon accumulation model. The conclusions of this research provide guidance for exploring multi-type reservoirs and multi-type hydrocarbon accumulation models.