Tight Gas Reserves Research Articles

Sedimentary Facies Controls for Reservoir Quality Prediction of Lower Shihezi Member-1 of the Hangjinqi Area, Ordos Basin

The tight gas reserves in the Hangjinqi area are estimated at 700 × 109 m3. Since the exploration of the Hangjinqi, numerous wells are already drilled. However, the Hangjinqi remains an exploration area and has yet to become a gas field. Identifying a paleo-depositional framework such as braided channels is beneficial for exploration and production companies. Further, braided channels pose drilling risks and must be properly identified prior to drilling. Henceforth, based on the significance of paleochannels, this study is focused on addressing the depositional framework and sedimentary facies of the first member (P2x1) of the lower Shihezi formation (LSF) for reservoir quality prediction. Geological modeling, seismic attributes, and petrophysical modeling using cores, logs, interval velocities, and 3D seismic data are employed. Geological modeling is conducted through structural maps, thickness map, and sand-ratio map, which show that the northeastern region is uplifted compared to northwestern and southern regions. The sand-ratio map showed that sand is accumulated in most of the regions within member-1. Interval velocities are incorporated to calibrate the acoustic impedance differences of mudstone and sandstone lithologies, suggesting that amplitude reflection is reliable and amplitude-dependent seismic attributes can be employed. The Root Mean Square (RMS) attribute confirmed the presence of thick-bedded braided channels. The results of cores and logging also confirmed the presence of braided channels and channel-bars. The test results of wells J34 and J72 shows that the reservoir quality within member-1 of LSF is favorable for gas production within the Hangjinqi area.

Dynamic prediction and influencing factors analysis of gas and water co-production stage in tight sandstone reservoir

Tight gas reserves account for a large portion of unconventional gas resources. At the stage of multiphase production of gas and water, gas productivity can be severely reduced because of water accumulation at the bottom of wellbore. This study investigates the effects of multiphase flow on bottomhole-pressure (BHP) estimation and productivity forecast for tight gas wells. The Beggs-Brill method is modified to calculate BHP by considering the phase changes of water in wellbore. The modified Beggs-Brill method is demonstrated with a relatively high accuracy (relative error <5%) in BHP calculation though comparing it against measured values. This study also establishes a new productivity model which mainly combines the water blockage effect caused by multiphase flow in the reservoir. The new model is further validated against field measurements. The results also suggest the relative permeability of gas and the mass ratio of gas and water follows a power-law relationship in the water-blockage area, and the gas productivity can be severely reduced once water blockage occurs for the tight gas wells.

Special features of tight gas reserves determination

Special features of tight gas reserves determination, based on material balance method, were characterized, since reliability of initial hydrocarbons in place determination plays important role in future field development planning, particularly on recovery rate, wells to be drilled, capital expenditures, surface facilities etc. Using the synthetic 3D model of gas reservoir, different development scenarios were evaluated according to the different spatial distribution patterns of petrophysical properties within the reservoir. Analyzing the obtained results, the authors fully confirmed an assumption made, that significant heterogeneity of reservoir properties makes a great impact on the shape of pseudo reservoir pressure curve vs cumulative gas produced and introduces significant errors into determination of initial gas in place. At the late stages of the development, the slope of P/z straight line changes, and this allows determination of much greater reserves’ volumes. Usage of pseudo reservoir pressure vs cumulative produced gas for determination of drained reserves in tight gas formation is especially risky, because the production data can indicate the true volumes of gas in place, only after the majority of the gas been produced. In most cases, the development period to acquire necessary data for correct volumes in place estimation exceeds the planning period. This factor introduces the significant error into future field development during the planning phase. Due to that, at the initial development stages, the error in drained volumes estimation can account for 50% out of true initial volumes in place. Based on conducted research, the potential error evaluation for tight gas reservoirs initial gas in place determination with decline pressure material balance method was performed. According to the results of computer simulation, the error can account for 25% from true initial gas in place in simulation model. This error significantly excesses the acceptable limits and can lead to wrong decisions in development planning

Technical strategies for effective development and gas recovery enhancement of a large tight gas field: A case study of Sulige gas field, Ordos Basin, NW China

Abstract Based on the analysis of influencing factors of tight gas recovery and reservoir geological characteristics, the types of remaining tight gas reserves in the Sulige gas field are summarized from the perspective of residual gas genesis to estimate residual gas reserves of different types and provide corresponding technical strategies for enhancing gas recovery. The residual gas reserves in the Sulige gas field can be divided into four types: well pattern uncontrollable, horizontal well missing, imperfect perforation, blocking zone in composite sandbodies. Among them, the uncontrolled remaining gas of well pattern and blocking zone in composite sandbodies are the main body for tapping potential and improving recovery factor, and well pattern infilling adjustment is the main means. Taking into account reservoir geological characteristics, production dynamic response and economic benefit requirements, four methods for infilling vertical well pattern, i.e., quantitative geological model method, dynamic controlled range of gas well method, production interference method and economic and technical index evaluation method, as well as a design method of combined vertical well pattern with horizontal well pattern are established. Under certain economic and technological conditions, the reasonable well pattern density of enrichment zone of gas field is proved to be 4 wells per square kilometers, which can increase the recovery rate of the gas field from 32% to about 50%. Meanwhile, five matching techniques for enhancing gas recovery aimed at interlayer undeveloped residual gas have been formed, including tapping potential of old wells, technological technology optimizing of new wells, rational production system optimizing, drainage and gas producing, and reducing waste production, which could increase the recovery rate for 5% based on well pattern infilling. The research results provide effective support for the long-term stable production of 230×108 m3/a of the Sulige gas field and production growth in the Changqing gas area.

A Volumetric Model for Evaluating Tight Sandstone Gas Reserves in the Permian Sulige Gas Field, Ordos Basin, Central China

To accurately measure and evaluate reserves is critical for ensuring successful production of unconventional oil and gas. This work proposes a volumetric model to evaluate the tight sandstone gas reserves of the Permian Sulige gas field in the Ordos Basin. The reserves can be determined by four major parameters of reservoir cutoffs, net pay, gas‐bearing area and compression factor Z, which are controlled by reservoir characteristics and sedimentation. Well logging, seismic analysis, core analysis and gas testing, as well as thin section identification and SEM analysis were used to analyze the pore evolution and pore‐throat structure. The porosity and permeability cutoffs are determined by distribution function curve, empirical statistics and intersection plot. Net pay and gas‐bearing area are determined based on the cutoffs, gas testing and sand body distribution, and the compression factor Z is obtained by gas component. The results demonstrate that the reservoir in the Sulige gas field is characterized by ultralow porosity and permeability, and the cutoffs of porosity and permeability are 5% and 0.15×10–3 μm2, respectively. The net pay and gas‐bearing area are mainly affected by the sedimentary facies, sand body types and distribution. The gas component is dominated by methane which accounts for more than 90%, and the compression factor Z of H8 (P2h8) and S1 (P1s1) are 0.98 and 0.985, respectively. The distributary channels stacked and overlapped, forming a wide and thick sand body with good developed intergranular pores and intercrystalline pores. The upper part of channel sand with good porosity and permeability can be sweet spot for gas exploration. The complete set of calculation systems proposed for tight gas reserve calculation has proved to be effective based on application and feedback. This model provides a new concept and consideration for reserve prediction and calculation in other areas.

Simulation of a multistage fractured horizontal well in a water-bearing tight fractured gas reservoir under non-Darcy flow

Reservoir development for unconventional resources such as tight gas reservoirs is in increasing demand due to the rapid decline of production in conventional reserves. Compared with conventional reservoirs, fluid flow in water-bearing tight gas reservoirs is subject to more nonlinear multiphase flow and gas slippage in nano/micro matrix pores because of the strong collisions between rock and gas molecules. Economic gas production from tight gas reservoirs depends on extensive application of water-based hydraulic fracturing of horizontal wells, associated with non-Darcy flow at a high flow rate, geomechanical stress sensitivity of un-propped natural fractures, complex flow geometry and multiscale heterogeneity. How to efficiently and accurately predict the production performance of a multistage fractured horizontal well (MFHW) is challenging. In this paper, a novel multicontinuum, multimechanism, two-phase simulator is established based on unstructured meshes and the control volume finite element method to analyze the production performance of MFHWs. The multiple interacting continua model and discrete fracture model are coupled to integrate the unstimulated fractured reservoir, induced fracture networks (stimulated reservoir volumes, SRVs) and irregular discrete hydraulic fractures. Several simulations and sensitivity analyses are performed with the developed simulator for determining the key factors affecting the production performance of MFHWs. Two widely applied fracturing models, classic hydraulic fracturing which generates long double-wing fractures and the volumetric fracturing aimed at creating large SRVs, are compared to identify which of them can make better use of tight gas reserves.

Tight Gas Reservoir Accumulation Conditions and Distribution Patterns during the Upper Palaeozoic of the East-Central Ordos Basin, Central China

The Upper Palaeozoic sandstones in the east-central Ordos Basin have abundant tight gas reserves. Studies of the accumulation conditions and distribution patterns of sandstone tight gas reservoirs in this region might provide important guidance for future exploration. The current study found that this region has satisfactory gas reservoir accumulation conditions, based on a systematic observation and analysis of rock core (lithic) images and well logging, source rock geochemistry, and reservoir bed physical property data. The primary source rocks are widely dispersed and have generally entered the mature or over-mature stages of gas generation. The reservoir beds have poor physical properties and strong heterogeneity. The mudstones in the regional seal (i.e., the upper Shihezi Formation) are generally undercompacted and have sufficient sealing capability. Due to the presence of mudstone interlayers, the gas-bearing capacities of these gas reservoirs show a gradual decrease from the P1s2 of Shanxi Formation toward both sides in a vertical direction. The horizontal distribution of the gas reservoirs is primarily concentrated in the sand bodies controlled by barrier island sand dams and subaqueous distributary river channel sediment microfacies. Tight sandstone reservoir beds usually contain gas, and “sweet spots” are the major high-yield regions in the area.

Developing new 3D seismic fracture interpretation methods for tight gas reservoirs

GeoSpectrum is finishing a study, funded in part by the U.S. Department of Energy (DOE), to establish a 3D seismic interpretation method for exploration and development of tight gas reserves in fractured sandstone reservoirs.