Journal of Petroleum Science and Engineering最新文献

This paper comprehensively analyzes the geochemical, mineralogical and petrographical properties combined with bulk kinetics modeling of the Domanik organic-rich carbonate from various depth intervals in Kuzminovsky oilfield (well № 26 R), Volga-Ural Basin, Russia. The results show that, the Domanik carbonate-rich samples are characterized by high content of the total organic matter (TOC) up to 13.31 wt %, and contain mainly Type II kerogen with a slight II/III kerogen type, reaching very good to excellent oil generation potential. Moreover, the studied samples contain hydrogen-rich kerogen, which expected to generate paraffin, naphthene and aromatic (P–N-A) oil with low wax content as demonstrated by the Py-GC Pyrolysis combined with the abundance of fluorescent alginite, amorphous organic matter, and bituminite as established from investigations via microscope. The maturity indicators demonstrated that, most of the examined Domanik carbonate-rich samples, with a burial depth between 1726.5 m and 1784.9 m, have generally reached low thermal maturity stages; thus, defining an immature to moderate-mature of oil generation window. The results of the kinetic models suggested that, Domanik carbonate-rich rocks with vitrinite reflectance (VRo) values in the range of 0.60–0.71%, have reached relatively low kerogen transformation ratio in the range of 10–20%, indicating low probability oil generation. These finding are confirmed by the presence of low oil saturation index of less than 100 mg HC/g rock (19.64–69.97). In addition, the results of thin section, scanning electron microscopy (SEM) and micro-computed tomography (micro-CT) showed that the studied samples are characterized by low porosity (up to 3.29%) with a wide pores size range, including interparticle, cavities, cracks and organic matter pores. The development of these pore types and their quality in the studied samples is mainly controlled by high mineralogical brittleness (i.e., carbonate and quartz) together with the high organic matter inputs. Therefore, according to the obtained results, characteristics and observations, the Domanik Formation has a high potential for commercial oil production, which typically requires hydraulic fracturing followed by an in-situ retort, mainly by thermal methods such as steam injection and in situ combustion process.

We present an integrated field development planning framework that bridges the integration gap through concurrently optimizing well placement, well trajectory, and facility layout. The novel algorithms implemented in the proposed framework break organizational silos between the reservoir, wells, and facility domains and provide reservoir engineers, drilling engineers, facility engineers, and economists with a shared planning platform. The presented solution is modular, flexible, and allows for multiple layers of granularity and, hence, a spectrum of solutions with different trade-offs between accuracy and efficiency needed as the field development plan is refined through its history. Multiple scenarios and example cases are presented illustrating the features of the integrated optimization framework and their applicability in different potential onshore and offshore oil and gas field development projects.

A novel machine learning based optimization algorithm for well trajectory design is presented and achieves significant improvements in computational time compared to traditional optimization approaches. Using a machine learning model to design a well trajectory was three orders of magnitude faster than the differential evolution algorithm which, in turn, was the fastest among the different optimization algorithms that we have tested. The proposed machine learning model drastically reduced the CPU requirements of the integrated solution and enabled the modeling of complex cases of hundreds of wells and associated facility building blocks.

Knowledge of the mechanical properties of natural gas hydrate reservoirs is fundamental to the safe and commercial extraction of natural gas hydrate. In our work, according to the characteristics of marine sediments in the South China Sea, gas hydrate samples with matrices containing 0%, 10%, 20%, and 30% montmorillonite or illite were prepared based on the saturated gas method. Under effective confining pressures of 2, 3 and 4 MPa, drained compression tests were performed on the samples. The results show that the clay type and clay content affect the failure strength and deformation of clayey silt hydrate sediments. The presence of clay causes the clayey silt hydrate samples to exhibit strain hardening behavior accompanied by shear shrinkage, and the failure strength and stiffness decrease with increasing clay content, as does the internal friction angle. The strength, stiffness, and Poisson's ratio of samples containing illite are generally greater than those containing montmorillonite. In addition, due to the strong bound water between particles, the cohesion of hydrate samples containing montmorillonite with similar hydrate saturations is higher than that of samples containing illite, while the internal friction angle is lower. These results are valuable for production well siting assessment in clayey silt hydrate reservoir and provide requisite theoretical basis for wellbore safety design.

Extra-heavy oil and bitumen (EHOB) comprise 30 percent of the remaining recoverable fossil fuel resources on Earth. This means EHOB could play an important role in a secure transition towards net zero emissions (NZE) by 2050. Technological developments, such as toe to heel air injection (THAI), have been shown to efficiently recover heavy oil with reduced environmental footprint. The Kerrobert project was the first to utilise the THAI technology in presence of bottom water (BW) in the reservoir. The project demonstrated a good performance (with average oil rate of 10 m³/day per well) compared to the conventional ISC operations in a BW situation. Lessons taken from the Kerrobert operational experience can assist the forthcoming THAI operations explicitly in the presence of BW. Dynamic field data for one of the best performing THAI pilot well pairs (K2), were analysed in this work. It was found that the K2 pilot must have experienced interference from K5, which is the closest neighbouring THAI well pair to the K2. Previously developed THAI models have not been validated against actual field data. A new field-scale THAI model in the presence of BW was constructed and, for the first time, validated against the field data from the Kerrobert project in this work. In addition, the quasi-staggered line drive well arrangement, as used for the K2 pilot, was studied. The daily and cumulative oil production rates were predicted well (the final agreement with field data was within 3 percent). The history matched model was then used to investigate the effect of the variation in air injection rates on THAI performance in presence of BW. Major developed zones during the propagation of the combustion front were numerically examined. It was demonstrated that extra air ingress from the neighbouring THAI well pair has caused a reduction in oxygen utilisation throughout the process. As a result, the simulated temperature profile declined with the increasing combustion time. The oxygen profile around the horizontal producer (HP) well was studied via the new history-matched model. An inversely proportional relationship was detected between the coke concentration and the oxygen profile around the HP well. It was found that the size of the steam zone, ahead of the combustion front, differs with variation in air injection rates. It was observed that some of the mobilised oil sank into the BW, leaving a significant amount of oil trapped in the reservoir. To prevent such an event, the location of the HP well was altered as a potential strategy to optimise the THAI efficiency. Consequently, the oxygen utilisation was improved by 13%, resulting in 73% higher cumulative oil production in comparison with the history-matched model.

Solid particulate additives are sometimes used to promote the uniform growth of multiple hydraulic fractures in horizontal oil and gas wells. The principle is that solid particulates block, accumulate, and form larger porous plugging zones preferentially at entrances of fracture taking in the most fluid volume. These porous zones create fluid flow resistance or additional pressure loss; thereby, inhibiting the growth of these dominant fractures and diverting fluid to suppressed fractures. While this technology is promising, governing design parameters and ramifications of placing solids diverters inside the fracture remain unclear. This paper models the propagation of multi-fractures with diverter pressure losses induced by the porous plugging zones. The resulting non-linear hydraulic fracturing problem is solved numerically with an Implicit Level Set Algorithm (ILSA) for each time step and the mechanisms of diversion are illustrated by comparing and contrasting cases with and without particle diverter. In both cases, during the fluid ramp-up period (pumping rate gradually increases from 0 to fracturing rate ($Q_T$)), the injection can be equally distributed among fractures before the stress interference affects the fluid allocation (Phase I). Then, stress interference starts to partition more fluid into outer fractures and suppress the growth of the middle fracture (Phase II). Once the perforation friction loss is sufficient to counteract the stress interaction, injection begins to shift to the middle fracture, but still gives a significantly non-uniform fracture growth (Phase III). At this point, solid diverter particles are introduced, leading to three additional phases of growth. Phase IV introduces solid diverters to the treatment at a reduced pumping rate. Particles bridge, accumulate and create porous plugging zones at the flow entrance. A higher pressure drop in outer fractures diverts injection fluids to the middle fracture. Phase V resumes the treatment rate to $Q_T$ without diverter. The increased pump rate in turn increases the pressure drop in outer fractures and diverts more fluids to the middle fracture. This results in a rapid extension velocity for the middle fracture, enabling it to have the chance to catch up with the longer outer fractures (in Phase VI). This process is controlled by the interplay among stress interference, perforation friction loss, and diverting pressure drop. These simulations demonstrate that a model-based optimization could improve the effectiveness of the diverter technology and promote a uniform multi-fracture growth.

Due to the instability of extracting elastic parameters from conventional elastic impedance variation with incident angle (EVA) pre-stack inversion and the fact that single-trace inversion does not consider the correlation between seismic traces and the lateral continuity of inversion results. An anisotropic total variation multitrace inversion method based on the $L_P$ norm constraint is proposed on the basis of EVA inversion. In this paper, the $L_P$ norm is used as the regularization constraint, the longitudinal and transverse difference operators are introduced, and the alternating direction multiplier algorithm and the 2D Sylvester equation solver algorithm are used as inversion algorithms to achieve a multitrace inversion of the elastic parameters. The feasibility of the method proposed in this paper is verified by making full use of the advantages of both methods and conducting trial calculations on some blocks of the Marmousi2 model. The method was further validated by applying it to actual data from marine shales of the Longmaxi-Wufeng Formation in the southern Sichuan Basin. The inversion results were validated using a combination of brittleness indices and microseismic monitoring to confirm the feasibility of the method in this paper.

Most oil fields today are mature, and the majority of the reservoirs in the Middle East are carbonate rocks characterized by high temperature high salinity (HTHS), heterogeneous mineral composition, and natural fractures. Enhanced oil recovery (EOR) methods are used for boosting oil recovery from the aged reservoirs beyond primary and secondary recovery stages. Nevertheless, it can be a challenging task to employ EOR techniques in these aged carbonate reservoirs. This is because carbonate reservoirs have mixed-to-oil-wet wettability with temperatures exceeding 85 °C and salinity of over 100,000 ppm, which renders secondary EOR-methods such as waterflooding ineffective. Therefore, even though carbonate reservoirs contain 60–65% of world's remaining oil, with immense intrinsic economic prospects, the oil recovery process from carbonate reservoirs remains a considerable challenge. Chemical-EOR (cEOR) techniques, like SP based cEOR, have shown marked promise in improved oil recovery, mainly from clastic reservoirs with medium temperature and salinity, unlike carbonate reservoirs. During SP-floodings, the surfactants get adsorbed due to the mineral composition of the carbonate rocks, and polymer degradation occurs due to HTHS conditions. Consequently, new surfactants and polymers have been structurally conformed and tested to improve their robustness and related recovery efficacy. For instance, Guerbet alkoxy-carboxylate surfactants demonstrated good stability at temperatures over 100 °C and salinities up-to 275,000 ppm, yielding tertiary recovery of 94.5% and low adsorption of 0.086 mg/g of rock. The cationic Gemini surfactants, zwitterionic or amphoteric class of surfactants are also suitable for HTHS carbonates. Besides, effective biosurfactants sourced from plant such as, soy, corn, etc., are non-toxic and readily biodegradable. The hydrophobically associating polyacrylamide (HAPAM) and its modified nanocomposite derivative can act as replacement surfactants, due to their wettability altering and robust characteristics. Novel polymers viz., NVP-based, novel smart thermoviscosifying polymers (TVP), soft microgel, and sulfonated polymers, are also relevant to HTHS carbonate applications. Xanthan gum, scleroglucan, and schizophyllan biopolymers have been noted to resist HTHS and low permeability conditions, requiring lower concentration and having low adsorption. Recent surfactant-polymer (SP) formulations also can be applicable for HTHS carbonates with excellent ternary recoveries (93.6%) and minimal retention (0.083 μg/g of rock). Such low retention values suggest low surfactants cost with minimal environmental impact. Moreover, several successful field applications in carbonates were conducted in preceding years; however, the performance of some novel surfactants under HTHS carbonates is yet to be fully understood. Hence, this comprehensive revie