Gas production from the gas hydrates in the Danube Delta of the Black Sea with different well configurations

All over the world; activities are carried out to meet the growing needs of oil and natural gas from domestic sources as much as possible. In this context, studies in the sea areas of Turkey, especially in the Black Sea, have gained great momentum. Gas hydrates are considered “near-future energy resources” due to their vast existence all around the world. This is due to the huge reserve potential of gas hydrates worldwide. Recently, China has tested gas production from methane hydrate-bearing clayey silts via horizontal well technology for the first time. One of the aims of this study is to investigate the effect of well configuration for gas production from gas hydrates in the Black Sea by numerical modeling with TOUGH + HYDRATE (T+H) code. In this study, two different models were studied in gas hydrate reservoirs in the conditions of the Black Sea (Single-layer homogeneous sand containing hydrates and multi-layered alternating sand/clay layers containing gas hydrates). Initially, an extensive literature review was conducted to create two hypothetical reservoir models representing the average conditions of the Black Sea. For this purpose, some of the parameters were obtained from the literature data related to the Danube Delta of the Western Black Sea and some of them were assumed to create two different hypothetical gas hydrate reservoirs. Basically, two different hypothetical reservoir models (Model 1 and Model 2) were created at a water depth of 1500 m. In Model 1, a single hydrate-bearing layer (HBL) is bounded by an impermeable overburden layer and an impermeable underburden layer. Moreover, hypothetical heterogeneous methane hydrate reservoirs (hydrate-bearing sand layer and hydrate-bearing turbidite) were formed in the Black Sea conditions. After forming these geological models, numerical gas production simulations from these reservoirs were conducted in different wellbore configurations (vertical and horizontal) by applying depressurization at different pressures (3 MPa, 4 MPa, and 5 MPa) with T + H simulator. With a higher depressurization rate, higher gas production was obtained from gas hydrates. However, at certain pressure values (less than 3 MPa), the gas production rate decreased due to fast cooling around the well. As seen in the results of Model 1-a simulations, after the complete gas hydrate dissociation, hundreds of days were needed to reach the original reservoir temperature by the heat transfer from boundaries. Water released with gas hydrate dissociation in homogenous hydrate-bearing sands (Model 1-a) moved through the bottom of HBL because of the gravitational effect. Gas production from Model 1 gas hydrates via 245 m-horizontal well is advantageous for the first production period (100 days to 200 days) compared to the vertical well. However, later, gas production with the vertical well became more advantageous. Gas production from Model 2 gas hydrates (alternating hydrate-bearing sands/clays) is quite complex compared to homogenous hydrate-bearing sand layers. Gas production from hydrate-bearing sand layers was faster than gas production in hydrate-bearing clay layers. Low-permeable hydrate-bearing clays avoided effective depressurization in HBL as depressurization simulations were provided with the 245 m-horizontal well in the top of HBL and near the bottom of HBL. Thus, higher gas production with the vertical well case was obtained in Model 2.