Low Gas Saturation Research Articles

Production Performance Analysis of Su-6 Well Block in Sulige Gas Field, Ordos Basin, China

As a tight sandstone gas reservoir of Su-6 well block in Sulige gas field, part of the gas wells have a poorer production performance with a faster decline rate of formation pressure and production, which is inconsistent with static reservoir parameters of gas well. In order to improve the productivity of gas well, on the base of static and dynamic classification of 232 gas wells, the reasons of inconformity between production performance and static reservoir parameters are analyzed from the four aspects of sand body connectivity, reservoir heterogeneity, gas saturation and fluid accumulation in wellbore. The results show that the main reasons causing the inconformity are the strong heterogeneity and poor sand body connectivity, and the secondary reasons are fluid accumulation in wellbore and low gas saturation. The results of this paper is of great significance to improve the productivity of gas wells and guide the development of ultra-low permeability gas reservoir.

FEATURES OF THE DEVELOPMENT OF WATER OIL ZONES OF DEPOSITS WITH HIGH VISCOSITY OIL

He process of developing platform-type oil fields is significantly affected by water oil zones (WOZ), which contain significant oil reserves. In most cases, there is a lag and insufficient production of WOZ in comparison with the initial pure oil parts of the reservoir. This lag is associated with many factors: technological (operating conditions, grid density) and geological (layer and zonal heterogeneity, the ratio of oil-saturated and water-saturated capacities, the configuration and dimensions of the upper water storage zone, their occurrence relative to the anhydrous parts of the deposits, etc.). This article discusses the features of the development of oil fields in the north-west of Bashkiria, establishes the relationship between the main development indicators, such as the maximum production rate, oil recovery coefficient, water cut, and density of the well network, both among themselves and from various external factors. Besides, additional difficulties are identified associated with increased viscosity, density and low gas saturation of reservoir oil in water oil zones. For analysis, we will consider 5 of the most characteristic sections of the Arlan area: Ashitskaya I, Saklovskaya IV, Arlanskaya V, Arlanskaya VI and Urtaulskaya VIII, where water oil and fully oil zones of the CVI layer are developed. These areas have significant oil reserves in the oil and water zones, while the selected areas are hydrodynamically quite isolated either by deflections or by the absence of reservoirs or low permeability formations, which determines the independence of the relationships established between the considered technological indicators from any external geological factors.

A compact ocean bottom electromagnetic receiver and seismometer

Abstract. Joint marine electromagnetic (EM) and seismic interpretations are widely used for offshore gas hydrate and petroleum exploration to produce improved estimates of lithology and fluids and to decrease the risk of low gas saturation. However, joint data acquisition is not commonly employed. Current marine EM data acquisition depends on an ocean bottom electromagnetic receiver (OBEM), and current seismic exploration methods use seismometers. Joint simultaneous data acquisition can decrease costs and improve efficiency, but conventional independent data receivers have several drawbacks, including a large size, high costs, position errors, and low operational efficiencies. To address these limitations, we developed a compact ocean bottom electromagnetic receiver and seismometer (OBEMS). Based on existing ocean bottom E-field receiver (OBE) specifications, including low noise levels, low power consumption, and low time drift errors, we integrated two induction coils for the magnetic sensor and a three-axis omnidirectional geophone for the seismic sensor to assemble an ultra-short baseline (USBL) transponder as the position sensor, which improved position accuracy and operational efficiency while reducing field data acquisition costs. The resulting OBEMS has a noise level of 0.1 nV m−1 rt−1 (Hz) at 1 Hz in the E-field, 0.1 pT rt−1 (Hz) at 1 Hz in the B-field, and a 30 d battery lifetime. This device also supports a Wi-Fi interface for the configuration of data acquisition parameters and data download. Offshore acquisition was performed to evaluate the system's field performance during offshore gas hydrate exploration. The OBEMS operated effectively throughout the operation and field testing. Therefore, the OBEMS can function as a low-cost, compact, and highly efficient joint data acquisition method.

Natural Gas Reservoir Characteristics and Non-Darcy Flow in Low-Permeability Sandstone Reservoir of Sulige Gas Field, Ordos Basin

In order to reveal the gas–water distribution and formation mechanism of the low-permeability sandstone gas reservoir, the gas reservoir distribution and the formation mechanism in a low-permeability sandstone gas reservoir are investigated using data obtained from a physical simulation experiment of gas percolation. The exploration and experimenting for petroleum in the upper Paleozoic gas pool of the Sulige gas field in the Ordos basin in this paper. Results showed that the gas reservoir is characterized by low gas saturation, a complex distribution relationship of gas–water, and weak gas–water gravity differentiation. The characteristics of gas distribution are closely related to permeability, gas flow, and migration force. The capillary pressure difference is the main driving force of gas accumulation. There exists a threshold pressure gradient as gas flows in low-permeability sandstone. The lower that permeability, the greater the threshold pressure gradient. When the driving force cannot overcome the threshold pressure (minimal resistance), the main means of gas migration is diffusion; when the driving force is between minimal and maximal resistance, gas migrates with non-Darcy flow; when the driving force is greater than maximal resistance, gas migrates with Darcy flow. The complex gas migration way leads to complicated gas- water distribution relationship. With the same driving force, gas saturation increases with the improvement of permeability, thus when permeability is greater than 0.15 × 10−3 µ m2, gas saturation could be greater than 50%.

Direct hydrocarbon indicator (DHI) pitfall assessment in prospecting pliocene globigerina biogenic gas play in “X structure”, Madura Strait, East Java Basin

Direct Hydrocarbon Indicator (DHI) has a major role in the exploration of Pliocene globigerina biogenic gas play in Madura Strait, part of East Java Basin. This study aimed to assess the DHI pitfall within the X Structure which triggered by the drilling result of Well X3 (dry hole) that contradict with Well X1 that successfully discovered gas even though both wells targeted the same reservoir body and DHI features. Low gas saturation that decreases the compressional velocity (Vp) is predicted to be the main reason behind the DHI pitfall. Considering the limitation of qualitative interpretation to investigate the DHI pitfall, this research uses seismic quantitative interpretations, such as fluid substitution modeling, amplitude variations with offset (AVO), seismic inversion, and rock physics analysis to get a full understanding behind the DHI features in X Structure. The 2D marine seismic survey consists of 49 seismic lines and wells data were used in this research. Fluid substitution and Vp-Vs-ρ modelling confirm that the DHI pitfall is related to the non-economic gas saturation (Sg < 10 %) within the reservoir. As for the AVO and inversion analysis indicated that the gas water contact (GWC) level is around 1,389 ms (± 4,023 ft SSTVD). Rock physics analysis shows that the poor reservoir quality is predicted to be the reason behind the low gas accumulation within the reservoir. Several properties cut off for gas zone were derived such as, P-impedance < 5,700 gr/cc*m/s, Vp/Vs < 2.0, porosity > 40 %, dan VCL < 22 %. This research concluded that the seismic quantitative interpretations were successfully used to assess the DHI pitfall and to delineate the economic gas accumulation zone.

Gas hydrate quantification in Walker Ridge block 313, Gulf of Mexico, from full-waveform inversion of ocean-bottom seismic data

The Gulf of Mexico (GOM) Joint Industry Project Leg 2 logging-while-drilling data in Walker Ridge lease block 313 (WR313) in the GOM detected gas hydrate in coarse- and fine-grained sediments at sites WR313-G and WR313-H. The coarse-grained units are thin ([Formula: see text]) and highly saturated, whereas the fine-grained unit is thick (approximately 200 m) with low saturation and fracture-filling gas hydrate. Unlike its coarse-grained counterpart, the seismic character of the fine-grained unit does not clearly indicate the presence of gas hydrate, which would likely have remained undiscovered in the absence of drilling. In this paper, through frequency-domain acoustic full-waveform inversion (FWI) of ocean-bottom seismometer data along a 2D multichannel seismic transect near sites WR313-G and WR313-H, we detect and quantify gas hydrate in the fine-grained unit. Key results are as follows: First, the base of the gas hydrate stability zone, which is not obvious in the reflection profile, can be discerned in the FWI results. Second, the gas hydrate in the fine-grained unit is mainly confined to the area between two sets of opposite-dipping normal faults implying that the fault architecture may be partially responsible for this gas hydrate accumulation and distribution.

Frequency-dependent AVO analysis using the scattering response of a layered reservoir

Sensitivity of reservoir properties to broadband seismic amplitudes can be weak, which makes interpretation ambiguous. Examples of challenging interpretation scenarios include distinguishing blocky reservoirs from fining sequences, low gas saturation from high gas saturation, and variable reservoir quality. Some of these rock and fluid changes might indicate stronger sensitivity to amplitudes over narrow frequency bands, which is a characteristic of frequency-dependent amplitude variation with offset (FAVO). We have developed a FAVO model for reservoir characterization, following a seismic scattering phenomenon through a set of isotropic elastic layers. The frequency dependency in our model comes from the time delays due to wave propagation within layers. The FAVO modeled response is a complex-valued amplitude varying with angle and frequency, and it is a function of the seismic velocities and thicknesses of individual layers, along with the conventional AVO response at all interfaces. Our FAVO seismic analysis consists of two main steps: (1) forward modeling using well logs to understand rock and fluid sensitivity to amplitudes to identify tuning frequencies with maximum amplitude excursions and (2) seismic analysis at tuning frequencies. With well-log models, we observed that the frequency-dependent tuning response is primarily dependent on the lithology stacking pattern of a reservoir; in the cases studied, the fluid and reservoir quality have secondary effects on the frequency dependence of the amplitudes. We evaluate synthetic models and field data from the Columbus Basin, Trinidad, to illustrate our frequency-dependent seismic analysis methods. For one of the sandstone reservoirs, a frequency-dependent attribute indicates better spatial resolution of the anomaly than a conventional amplitude extraction. FAVO attributes are complementary to conventional AVO attributes.

Analysis of Water–Gas System Equilibria in Jurassic–Cretaceous Reservoirs (by the Example of the Yamal-Kara Depression)

Abstract —The paper presents results of the pioneering study of equilibria in the water–gas system by the example of Jurassic–Cretaceous deposits of the Yamal–Kara depression located within northern West Siberia and its Arctic regions. Numerical modeling of physicochemical equilibria and evasion–invasion processes in the water–gas system allowed determination of the degree of groundwater saturation with gases and the nature of diffusive redistribution of gases in the media that form at the hydrocarbon deposit–groundwater contact. According to the degree of water saturation with gases (Kg), aquifers with poorly (&amp;lt;0.2) to ultimately (0.8–1.0) gas-saturated waters have been established. The revealed increase in the degree of groundwater saturation with gases in sinking producing reservoirs reflects its dependence on their total gas saturation. All waters with a total gas saturation of more than 1.8 L/L become ultimately saturated with gases (Kg = 1.0), thus theoretically predetermining the formation of hydrocarbon accumulations. Major gas condensate deposits are confined to the zone of gas-saturated waters with Kg from 0.8 to 1.0, while oil accumulations, to waters with lower gas saturation. Based on the established nature of water–gas, we can argue that oil and gas accumulations in Jurassic–Cretaceous reservoirs act as a conservative element of the lithosphere, i.e., its geologic and geochemical “relics”. The surrounding subsurface waters, as a more active constituent of the system, have largely anticipated its geochemical development, which is manifested in the differentiation of the fugacity ratios of individual gases in groundwater and hydrocarbon accumulations. The composition of the latter is therefore subjected to slow directional changes while the equilibrium is established, to usher in the qualitatively new state of the geochemical water–gas system.

Effect of Fluid Pressure and Pore Structure on Tight Sand Gas Saturation—Evidence from Micro-CT Simulation Experiment

Summary Numerous technical papers have been published on the reservoir evaluation of tight sand gas in recent decades. It is believed that tight sand gas is characterized by low permeability, complex pore structure, abnormal pressure, and low gas saturation. Researchers have characterized tight gas in terms of, for example, statistics; and some of them are increasingly interested in the effect of fluid pressure and pore structure on gas saturation. However, there is still a lack of effective experimental and mechanism analysis. The focus of this paper is to investigate the effect of two factors on controlling the tight gas saturation. A method was proposed for determining the in-situ injection pressure of the DB 2 gas reservoir in the Kuqa area during the gas-accumulation period, and the result was 1.2 MPa. A polyetheretherketone carbon-fiber core holder (maximum temperature 180 °C, maximum confining pressure 30 MPa) was designed for the microcomputed-tomography (CT) simulation experiment. After that, four physical simulation experiments of different fluid pressures (0.1, 0.5, 1.5, and 5.0 MPa) were implemented using X-ray CT and the new core holder to study the effect of fluid pressure and pore structure on gas saturation. The results show that the fluid pressure and micropore connectivity are important factors for gas-saturation increase; the number of gas clusters (connected pores containing gas) increases with the increase of fluid pressure and the maximum volume of gas clusters increases with the increase of pore connectivity. The connected pores with the largest volume are an important source of gas-saturation contribution. The three types of modes (the blowing balloon mode, stitching mode, and composite mode) of microscopic gas-cluster formation are discussed. The blowing balloon mode is key to gas-saturation growth in the period of low fluid pressure or the early stage of the injection process. The stitching mode is key to gas-saturation growth in the period of high fluid pressure or the late stage of the injection process. The above research system investigates the quantitative control of fluid parameters (pressure) and reservoir parameters (pore structure) on gas saturation, which might change the situation where previous research was too focused on the pore-structure and fluid-pressure characterization, with a lack of quantitative control analysis of reservoir gas saturation. It provides a valuable reference and framework for the reader to conduct further quantitative research on tight gas saturation.

Impact of pore fluid heterogeneities on angle-dependent reflectivity in poroelastic layers: A study driven by seismic petrophysics

The present study demonstrates the application of seismic petrophysics and amplitude versus angle (AVA) forward modeling to identify the reservoir fluids, discriminate their saturation levels and natural gas composition. Two case studies of the Lumshiwal Formation (mainly sandstone) of the Lower Cretaceous age have been studied from the Kohat Sub-basin and the Middle Indus Basin of Pakistan. The conventional angle-dependent reflection amplitudes such as P converted P (RPP) and S (RPS), S converted S (RSS) and P (RSP) and newly developed AVA attributes (deltaRPP, deltaRPs, deltaRSS and deltaRSP) ) are analyzed at different gas saturation levels in the reservoir rock. These attributes are generated by taking the differences between the water wet reflection coefficient and the reflection coefficient at unknown gas saturation. Intercept (A) and gradient (B) attributes are also computed and cross-plotted at different gas compositions and gas/water scenarios to define the AVO class of reservoir sands. The numerical simulation reveals that deltaRPP, deltaRPS, deltaRSS and deltaRSP are good indicators and able to distinguish low and high gas saturation with a high level of confidence as compared to conventional reflection amplitudes such as P-P, P-S, S-S and S-P. In A-B cross-plots, the gas lines move towards the fluid (wet) lines as the proportion of heavier gases increase in the Lumshiwal Sands. Because of the upper contacts with different sedimentary rocks (Shale/Limestone) in both wells, the same reservoir sand exhibits different response similar to AVO classes like class I and class IV. This study will help to analyze gas sands by using amplitude based attributes as direct gas indicators in further gas drilling wells in clastic successions.

Uncertainty analysis of hydrocarbon in place calculation using 3D seismic and well data during appraisal stage – Case study of Goldie Field, offshore Sarawak

Goldie Field located offshore Sarawak was previously estimated to be less than 200 Bscf of gas initially in place (GIIP) and well-4 of a major reservoir in the field was classified as a dry hole. In this study, the uncertainty of hydrocarbon in place of a major reservoir in Goldie Field is estimated with limited seismic and well data to determine if an oil column is present in the reservoir. 3D Stacking velocity incorporated into well velocity from check shots were analysed and the best method or equation for time-to-depth conversion was determined. Gross bulk volume (GBV) was developed using area depth method. Both deterministic and probabilistic calculations were conducted and analysed with the uncertainties. The plot of true vertical depth (TVD) versus two-way time (TWT) velocity function derived from seismic interpretation time at well location and velocity function derived from pre-stack time migration (PSTM) were used to determine the accuracy of the time-to-depth conversion. Pickett and Hingle graphical solution equation was used to derive the water resistivity (Rw). Log base saturation height function was calculated using Cuddy's method and Harrison-Skelt's equation. The study has produced new depth structure maps that shows a highly correlated values up to a regression coefficient of 0.99 and seismic attributes that assisted in modelling of the reservoir in Goldie Field. Check shot analysis shows that a linear function Vavg versus TWT and a second order polynomial function for TVD vs TWT are accurate for seismic time conversion. Revaluation of well logs and other well data has produced new porosity, water saturation, net to gross ratio and formation volume factor. Well-4 was classified as a dry hole in PETRONAS in-house report, but the cuddy's plot for R3 sand in well-4 indicates existence of low saturation gas. This study has produced an estimated GIIP of 360 Bscf for R3 sand and well-4 has penetrated deeper sands previously interpreted to be wet. The seismic interpretation and petrophysical evaluation showed that Excel graphics and mathematical analysis improved the quality of the analysis, and the results show good comparison to other specialized software provided by vendors.

Study and Application of Novel Cellulose Fracturing Fluid in Ordos Basin

Due to low gas saturation, less than 10% porosity, around 0.05 mD permeability and below 0.85 pressure coefficient, stimulation treatments are necessary in order to get economic production. Development speed of this block had been seriously affected because of significantly lower single well production than other parts of the Sulige Gas Field. Low concentration crossed-linked guar fracturing fluid is now commonly used in this area. As small size pore throat, high clay content and water lock, this gas deposit is sensitive to treatment fluid, thus the flowback time of fractured well is very long and production is generally low. In this paper we introduce a new fracturing fluid which can be crossed-linked in acidic water-based fluids. This fluid contains a kind of cellulose, which is completely soluble with no residue. Cellulose was used as additive agent in drilling and completion fluid twenty years ago, therefore, its application was greatly limited as poor stability of performance. New cross-linked agent and additives could solve this problem. Because of being compatible well with the reservoir fluids, the damage of fracturing fluid is relatively low. Proppant carrying capacity of this new fluid can be compared with low concentration crossed-linked guar fracturing fluid. The new fluid has been used in 6 vertical wells, with 100% treatment success-rate and 8.6×104m3/d average production rate. Compared with the nearby wells which had the same pay formation and were fractured with the similar fracture treatment scale by low concentration guar fracturing fluid, the flowback time was shortened by 53% and gas production was doubled. In conclusion, this new fracture fluid can reduce treatment time and cost, but increase gas production.

Dissociation characteristics of water-saturated methane hydrate induced by huff and puff method

The world has huge reserves of gas hydrates which are considered to be a potential energy resource. Therefore, developing methods for commercial gas production from hydrate reservoirs are attracting extensive attention. In order to mimic the geological condition of the practical oceanic hydrate reservoir, water-saturated hydrate sample with low gas saturation (8.27%) was obtained by the formation process of multi-step water injection. The huff and puff (H&P) method (above or below the equilibrium pressure for hydrate dissociation) was applied for hydrate dissociation. Results show that the system pressure rises with the increase of the H&P cycle for the H&P method above the equilibrium pressure. Furthermore, the dissociated hydrate in the injection period can be reformed in the soaking and production periods, and hydrate saturation increases mildly after each cycle of H&P. Hence, the H&P method above the equilibrium pressure is unpractical for hydrate dissociation with low gas saturation. However, the hydrate in the reservoir can be completely dissociated by the H&P method below the equilibrium pressure. Therefore, in the water-saturated hydrate reservoir, the regular H&P method is not suitable. The regular H&P should combine with depressurization method for gas recovery from the water-saturated hydrate reservoir.

Hydrodesulfurization of Iraqi Atmospheric Gasoil by Ti-Ni-Mo/γ-Al2O3 Prepared Catalyst

This study investigates the improvement of Iraqi atmospheric gas oil characteristics which contains 1.402 wt. % sulfur content and 16.88 wt. % aromatic content supplied from Al-Dura Refinery by using hydrodesulfurization (HDS) process using Ti-Ni-Mo/γ-Al2O3 prepared catalyst in order to achieve low sulfur and aromatic saturation gas oil. Hydrodearomatization (HDA) occurs simultaneously with hydrodesulfurization (HDS) process. The effect of titanium on the conventional catalyst Ni-Mo/γ-Al2O3 was investigated by physical adsorption and catalytic activity test.Ti-Ni-Mo/γ-Al2O3 catalyst was prepared under vacuum impregnation condition to ensure efficient precipitation of metals within the carrier γ-Al2O3. The loading percentage of metals as oxide; titanium oxide 3 wt. %, nickel oxide 5 wt. % and molybdenum oxide 12 wt. %. The performance of the synthesized catalyst for removing sulfur and aromatic saturation were tested at various temperatures 275 to 350°C, LHSV 1 to 4h-1, constant pressure 40 bar and H2/HC ratio 500 ml/ml.Results showed that the sulfur and aromatic content were reduced at all operating conditions. Maximum sulfur removal was 75.52 wt. % in gas oil on Ti-Ni-Mo/γ-Al2O3 at temperature 350˚C, LHSV 1h-1, while minimum aromatic content achieved was 15.6 wt. % at the same conditions.&#x0D;

Problems in the development of high-rank CBM horizontal wells in the Fanzhuang–Zhengzhuang Block in the Qinshui Basin and countermeasures

Coal reservoirs in the Qinshui Basin are characterized by high thermal evolution degree, low permeability, low reservoir pressure, lower gas saturation and strong heterogeneity, so its coalbed methane (CBM) development is quite difficult. In this paper, the development practice of high-rank CBM horizontal wells in the Fanzhuang–Zhengzhuang Block was analyzed in terms of geological and engineering factors to clarify the productivity influencing factors, suitable geological conditions and potential tapping countermeasures of multi-lateral horizontal wells. It is shown that the reasons for the low development efficiency of multi-lateral horizontal wells are divided into three types. The first one is geological factor, such as encountering low CBM content areas or faults. The second is engineering factor, such as drilling fluid plugging, drilling collapse, drainage collapse and dust coal blockage. The third is the combination of both factors. It is concluded that encountering low CBM content areas and faults, collapse and blockage are the main reasons for the low production of multi-lateral horizontal wells in the Zhengzhuang–Fanzhuang Block, with the CBM content higher than 20 m3/t, the ratio of critical desorption pressure and reservoir pressure higher than 0.7 and vitrinite reflectance (Ro) higher than 3.8. The prerequisite for an open-hole horizontal well in this area to produce CBM at a high rate is that the well lies in the tensile stress zone. Finally, the countermeasures to tap the potential of some inefficient wells were put forward. First, the inefficient wells which are blocked with dust coal or collapsed in the later stage should be stimulated based on classifications. And second, it is necessary to explore new types of horizontal wells so as to deal with borehole collapse and continue the operation in the later stage by using tree-like roof horizontal wells, single-lateral horizontal wells with casing or screen completion and fish-bone horizontal wells.

Quantitative interpretation of carbonate reservoir rock using wireline logs: a case study from Central Luconia, offshore Sarawak, Malaysia

The current study focuses on the quantitative evaluation of petrophysical parameters of selected wells using wireline log data in Central Luconia, offshore Sarawak. Based on the relatively high resistivity and, low-neutron/-density log responses, three major zones are identified. These include gas-bearing zones (Zone-1 and Zone-3) and mixed zone (Zone-2). The gamma ray, neutron and density logs confirmed that Well A was composed of carbonate rocks ranging from limestone to dolomite. Zone-1 and Zone-3 consist of limestone, whereas Zone-2 contains dolomite. The average porosity of these zones (Zone-1, Zone-2 and Zone-3) are 15.7, 4.3 and 13.7%, whereas gas saturation is 83, 41 and 93%, respectively. The permeability values are 543 mD (Zone-1), 47.7 mD (Zone-2) and 601.5 mD (Zone-3). The water saturation value in Zone-2 is very high, up to 66% compared to Zone-1 and Zone-3 which are 17 and 7%, respectively. It is pertinent to mention that Zone-1 and Zone-3 contain movable gas (i.e., HC movability index is less than 0.7). Furthermore, bulk volume water values in three zones (0.012, 0.0083 and 0.009) indicate the presence of irreducible water. In contrast, pore-filled dolomite cement is mostly from Zone-2, indicating high water, low gas saturation, low porosity and less movability index values, which indicate the presence of high microporosity. Additionally, bulk volume water suggests that these micropores are saturated with irreducible water. High microporosity affects the wireline log response in Zone-2 and therefore provides misleading information.

Huff and Puff Induced Hydrate Dissociation Above and Below the Phase Equilibrium Point with Low Gas Saturation

In order to simulate the hydrate condition which is similar to the practical oceanic hydrate reservoir, hydrate samples with low gas saturation (8.4%) was obtained by the formation process of multi-step water injection. The huff and puff method (above the equilibrium pressure and below the equilibrium pressure) was employed for hydrate dissociation. When the injection temperature is lower than 20 oC, the system pressure rises with the increase of the huff and puff cycle for the huff and puff method which is above the equilibrium pressure. In addition, the gas production rate decreases over time and the water production rate is lower than that of water injection, indicating that the huff and puff method above the equilibrium pressure is unpractical for hydrate dissociation with low gas saturation. However, the huff and puff method below the equilibrium pressure can dissociate the hydrate in the reservoir completely.

Predicting Reservoir Performance Using the Elastic Properties of Well Logs in Fabi Field, Niger Delta Basin in Nigeria

In recent times, characterization of reservoir using elastic properties of the well logs is limited to discrimination of reservoir fluids and lithologies which do not precisely reflect reservoir characteristics. In this study, we propose a robust approach that uses the well log derived attributes to predict the effects of the production related changes and performance levels of the reservoirs. First, the elastic attributes were generated from the well logs using the transform menu of the E-log program. The appropriate pairs of the attributes were cross-plotted and color overlay of the most robust attributes established. The cross-plot of Lambda-Rho versus Mu-Rho revealed the gas charged sand, brine charged sand and streak of shale in HD5000 reservoir. The color overlay of the lambda-Rho showed very high degree of brine saturation and very low gas saturation. The cross plot of velocity ratio versus P-impedance in HD8000 reservoir revealed hydrocarbon charged sand which was associated with very low velocity ratio, acoustic impedance values and brine saturation. The color overlay of acoustic impedance showed very high hydrocarbon saturation and low brine saturation. The cross plot of Mu-rho versus density at HD9000 reservoir also revealed the hydrocarbon charged sand (very low-density values) and brine charged sand. The color overlay of density revealed relatively high hydrocarbon and low brine saturation. The high brine saturation in the reservoirs probably resulted from increase in formation water due to production and steam injection program which is an indication of reservoir depletion. However, the results indicate that HD8000 and HD9000 reservoirs are still active for more hydrocarbon production while HD5000 reservoir is not.

The experimental modeling of gas percolation mechanisms in a coal-measure tight sandstone reservoir: A case study on the coal-measure tight sandstone gas in the Upper Triassic Xujiahe Formation, Sichuan Basin, China

Tight sandstone gas from coal-measure source rock is widespread in China, and it is represented by the Xujiahe Formation of the Sichuan Basin and the Upper Paleozoic of the Ordos Basin. It is affected by planar evaporative hydrocarbon expulsion of coal-measure source rock and the gentle structural background; hydrodynamics and buoyancy play a limited role in the gas migration-accumulation in tight sandstone. Under the conditions of low permeability and speed, non-Darcy flow is quite apparent, it gives rise to gas-water mixed gas zone. In the gas displacing water experiment, the shape of percolation flow curve is mainly influenced by core permeability. The lower the permeability, the higher the starting pressure gradient as well as the more evident the non-Darcy phenomenon will be. In the gas displacing water experiment of tight sandstone, the maximum gas saturation of the core is generally less than 50% (ranging from 30% to 40% and averaging at 38%); it is similar to the actual gas saturation of the gas zone in the subsurface core. The gas saturation and permeability of the core have a logarithm correlation with a correlation coefficient of 0.8915. In the single-phase flow of tight sandstone gas, low-velocity non-Darcy percolation is apparent; the initial flow velocity (Vd) exists due to the slippage effect of gas flow. The shape of percolation flow curve of a single-phase gas is primarily controlled by core permeability and confining pressure; the lower the permeability or the higher the confining pressure, the higher the starting pressure (0.02–0.08 MPa/cm), whereas, the higher the quasi-initial flow speed, the longer the nonlinear section and the more obvious the non-Darcy flow will be. The tight sandstone gas seepage mechanism study shows that the lower the reservoir permeability, the higher the starting pressure and the slower the flow velocity will be, this results in the low efficiency of natural gas migration and accumulation as well as low gas saturation. The laboratory modeling on gas migration accumulation mechanism in coal-measure tight sandstone can provide a theoretic foundation to reveal the tight sandstone gas enrichment regularity, evaluation of prospecting area, and the study of development mechanism.

Velocity model building and imaging in the presence of shallow gas

Multiple shallow layers of low saturation gas charged sands cause poor seismic imaging and hamper exploitation of many oil and gas discoveries in SE Asia. These gas ‘clouds’ are characterized by bright high amplitude reflectors of low P-wave velocity beneath which the seismic reflections have delayed P-wave travel times, reduced bandwidth, reduced reflected and transmitted amplitudes and associated phase distortion (Figure 1). All gas clouds are not equal, the appearance of gas clouds varies worldwide and within regions. A single gas-charged sand may sometimes have almost no effect on P-wave propagation; a shallow region of limited spatial extent may sometimes be undershot resulting in an interpretable image or multiple shallow layers can result in complete ‘wipeout’ of the final image. We believe that both anelastic losses and multiple scattering phenomena (indicated by rays on Figure 1) contribute to weak reflected energy beneath the gas-charged sands. A similar problem in the North Sea led to the development of multi-component seabed seismic solutions utilizing converted waves to penetrate beneath the gas (Berg et al., 1994). These solutions have been successfully applied to the largest of the Malaysian producing fields and are the PETRONAS preferred technical solution (e.g. Radzi et al., 2015). As with many problems, a mixture of acquisition and processing related solutions produces the optimal result but sometimes processing alone can produce a cost-effective result. Despite cost reductions and technical advances, converted wave imaging is still expensive, difficult and time consuming. In this paper we attempt to build an efficient and accurate workflow for velocity model building of P-wave data in order to best exploit the latest imaging algorithms. We use a mixture of synthetic and real data examples from offshore Malaysia to illustrate this difficult and unresolved problem.