The nature of carbonate reservoirs promotes the adsorption of oil onto the rock surface hence making oil recovery a challenge even with the interventions of varied chemical EOR methods. Recently, low salinity water flooding has become of great interest since it is cost-effective and environmentally friendly. Although low salinity waterflooding has been highly investigated in sandstone reservoirs, it is not the same for carbonate reservoirs due to its complexities. Nonetheless, it has been proposed as a favourable technique to mobilise the trapped oil in carbonate reservoirs. Wettability alteration is regarded as the most accepted mechanism for low salinity flooding but has not been well understood making field scale applications doubtful. In this paper, we present a detailed review of the wettability alteration mechanisms in carbonate reservoirs during low salinity waterflooding. Parameters influencing wettability alteration in carbonates and the interactions that occur at the rock/brine/oil interface are also presented. The different methods utilised for wettability measurements during low salinity waterflooding are also reviewed including their drawbacks and advantages and recommendations. This will provide an improved understanding of the low salinity flooding application in carbonate reservoirs.

The sand intervals of the Early Cretaceous Lower Goru Formation are a conventional reservoir, generally distributed in the Middle and Lower Indus Basin of Pakistan. Lithostratigraphically formation is classified into two parts; the upper parts are predominantly composed of shale, siltstone, and thin layers of alternate shale and sandstone, while the lower parts are composed of sandstone with interlayering of shale and limestone. The sandstone of the Lower Goru Formation has been further divided into A, B, C, and D sand intervals based on reservoir quality. Detailed depositional facies and reservoir characteristics are essential for the evaluation of hydrocarbon exploration and development. This paper aims to evaluate the depositional environment and reservoir characterization of the siliciclastic reservoir of the Early Cretaceous Lower Goru Formation by integrating the gamma-ray log patterns and petrographic analysis and scanning electron microscopic (SEM) analysis. Petrographic characterization of the sand intervals and Gamma-ray log signatures were used for the interpretation of the depositional environment of the reservoir intervals. Petrographic analysis reveals that the sandstone of the Lower Goru Formation is fine-to medium-grained, well-sorted, arkose or feldspathic arenite. Primary intergranular macroporosity, secondary intragranular macropores, and Intercrystalline micropores were identified within the sandstone by the SEM analysis. The diagenetic analysis suggests that the sandstone possesses high porosity, low permeability, and has undergone significant alterations such as compaction, quartz cementation, feldspar dissolution, and clay minerals alteration. Five electrofacies are interpreted based on gamma-ray log patterns including (1) funnel shape (FA); (2) bell shape (FB); (3) cylindrical shape (FC); (4) bow shape (FD); and (5) serrated shape (FE) patterns. The interpreted facies results reveal shoreface environment for A-sand, Tidal flat for B-sand, mixed tidal flat for C sand, Tide dominated mixed for D-sand, and transgressive shelf for E−sand. The present study will be helpful for the assessment of the reservoir quality of the Early Cretaceous Lower Goru Formation for further exploration and development in the Indus Basin of Pakistan.

Wellbore instability is an issue that, if left untreated, can cause wells to collapse, resulting in human, environmental, equipment, and revenue losses. Drilling fluids have been used to enhance the drilling process by lubricating and cooling the drill bit, eliminating cuttings, and most importantly, by improving the stability of the well by preventing fluid loss. However, there has been an increase in operational demands and challenges that call for drilling fluids to be more effective, economical, sustainable, and environmentally friendly. With shales that have infinitesimally small pores, nanoparticle additives in drilling fluids can be crucial in providing the properties that are necessary to prevent fluid loss and provide wellbore stability while meeting the operational demands of the present day. Therefore, this paper examines the use of nanoparticle additives including copper (II) oxide (CuO), magnesium oxide (MgO), and aluminum oxide (Al₂O₃) where they are tested under three conditions using the permeable plugging tester (PPT), high-temperature high-pressure (HTHP) fluid loss apparatus, and API low-temperature -low-pressure (LTLP) fluid loss apparatus under concentrations of 0.03% and 0.10%. Finally, based on the results, each nanoparticle sample (particle sizes between one and 100 nm) performed well in contributing to the aim of this project. CuO is the most effective inhibitor across all concentrations and under the three different conditions. It contributed to reducing the fluid loss from 37.6 mL to 18.2 and 13.2 mL, which is between 52% and 65% of fluid reduction. For MgO, it contributed to fluid loss reduction to 23.8 mL and 15 mL, which translated to 37%-60% of fluid loss reduction. The use of Al₂O₃ nanoparticles resulted in a fluid loss reduction to 33.6 mL and 17.8 mL, reducing the fluid loss up to 11%, at HTHP and up to 53% at LTLP. Unlike CuO and MgO, Al₂O₃ was less effective under HTHP conditions when compared to LTLP conditions. Al₂O₃ did not suffer as a significant diminishing benefit with increasing concentration in LTLP conditions however which means that at a higher concentration, it may begin to be more effective. Each material used in this study has its own specific and technical characteristics that will help create a progressive amount of property, such as providing stability and withstanding the high-temperature and high-pressure condition downhole.

Oil exploration and production, well stability, sand production, geothermal drilling, waste-water or CO₂ sequestration, geohazards assessment, and EOR processes such as hydraulic fracturing, require adequate information about in-situ stresses. There are several methods for analyzing the magnitude and direction of in-situ stresses. The evaluation of tensile fractures and shear fractures in vertical oil and gas wellbores using image logs is one of these methods. Furthermore, when image logs are run in boreholes, they can be extremely costly and possibly stop the drilling. The data for this study were gathered from seven directional wells drilled into a strike-slip fault reservoir in southern Iran. Vertical stress, minimum horizontal stress, pore pressure, Poisson's ratio of formations, and 233 mud loss reporting points make up the entire data. This is the first time maximum horizontal stress direction has been calculated without referring to image log data. In addition, the points of lost circulation were categorized into natural and induced fracture. The results revealed that, the maximum horizontal stress direction of the reservoir was calculated at 65° northeast-southwest. The error rate is roughly 10° when comparing the results of this investigation to those obtained from the image log. The maximum horizontal stress direction is calculated precisely. In terms of tensile fracture pressure, the in-situ stress ratio identifies the safest as well as the most critical inclination and azimuth for each well.

Various mechanisms are employed to interpret the low water recovery during the shale-gas production period, such as extra-trapped water in the fracture network, water imbibition due to osmotic pressure and capillary pressure. These lead to the difficulty of water flow, which could be described by low-velocity non-Darcy's law known as threshold pressure gradient (TPG). In this paper we firstly employ the low-velocity non-Darcy's law to describe the water flow and use Darcy flow accounting for slip flow and free molecular flow mechanisms to model gas flow in the shale formation. The sensitive study using numerical simulation shows that the proposed flow model could model the low fracturing liquid recovery and that large pseudo TPG leads to lower fracturing liquid recovery. Thus, the proposed model would give new insight to model the low water recovery in shale formations.

Gas cap blow down strategy is normally deployed for Ultra-thin oil rim reservoirs with huge gas caps due to extremely high gas oil ratios from wells in such reservoirs. The current state leads to loss of production from the oil reserves due to high initial reservoir pressure thus, reducing its net present value. Data on important factors essential to the productivity of oil rim reservoirs are used to build a heterogeneous ultra-thin reservoir with a time step of 10,000 days using the Eclipse software and its embedded correlations. The reservoir is subjected to a gas cap blowdown via a gas well, then an oil well is initiated into the model at onset and after time periods of 2000 days, 4000 days, 6000 days and 8000 days to estimate the oil recovery. It is expected that due to the large nature of the gas cap, pressure decline will be drastic and leading to a low oil recovery, hence the injection of water and gas at different rates at the periods indicated. The results indicate an oil recovery of 4.3% during gas cap blow down and 10.34% at 6000 days. Peak oil recoveries of 12.64% and 10.80% are estimated under 30,000 Mscf/day at 4000 days and 1000 stb/day at 6000 days respectively. This shows an incremental oil recovery of 8.34% and 6.5% over that recorded during gas cap blow down. The results also indicate that the gas production at those periods was not greatly affected with an estimated increment of 257 Bscf recorded during 30,000 Mscf/day at 4000 days. All secondary injection schemes at the respective time steps had positive impact on the overall oil recoveries. It is recommended that extra production and injection wells be drilled, enhanced oil recovery options and injection patterns be considered to further increase oil recovery.

Yaha condensate gas reservoir is condensate gas reservoir developed by gas injection in the Tarim Basin. The practice of gas injection in condensate gas reservoir shows that the key to improve gas injection effect is to control gas channeling. Dynamic monitoring shows that there is no instantaneous miscibility between dry gas and condensate gas during gas injection. Based on the principle of entropy increase and mass transfer kinetics, the phase behavior of condensate gas and dry gas in reservoir is analyzed theoretically. The new technique to improve condensate recovery is adopted for condensate gas field. By using the density difference and seepage characteristics of dry gas and condensate gas, the injected dry gas cap is formed at the top of the gas reservoir, and the three-dimensional displacement is realized by the expansion of dry gas cap. Gas injection gravity assisted flooding technology is to realize vertical displacement of injected gas through the expansion of dry gas cap by using gravity differentiation caused by gas density difference. This technology can keep the front edge of gas injection advance evenly and solve the problem of gas channeling in the process of cyclic gas injection.

The purpose of this research is to look into the augmentation of silica nanoparticles (NPs) with low salinity (LowSal) brine for EOR. A series of analyses, including oil/water interfacial tension (IFT) and rock wettability tests were undertaken to determine an optimal dispersion to flood into a porous carbonate core with a defined pore size distribution. At 60°C and 14.5 psi, the maximum drop (i.e., roughly 12.5 mN/m) in oil/water IFT by 0.3 wt% brine occurred, but when 0.08 wt% silica was added to the brine, the IFT reduced to 14.51 mN/m at 60°C and 14.5 psi. The wettability analysis revealed a significant reduction in contact angle, from 142° to 72° and 59°, using 0.04 and 0.08 wt% silica in LowSal brine, but the extent reduced by brine alone was insufficient. The results of rock pore size characterization were discussed in terms of the accomplishment of operating EOR in the porous medium in the presence of NPs. The addition of 0.08 wt% silica to the injected brine resulted in an additional oil recovery of 16.3% OOIP as well as a significant shift in the endpoints/cross-points of the oil/water relative permeability curves. The findings of this research might help improve oil recovery from asphaltenic oil reservoirs or, more environmentally friendly, remediate petroleum crude-oil polluted soil.

During the solid fluidization exploitation of marine natural gas hydrates, the hydrate particles and cuttings produced via excavation and crushing are transported by the drilling mud. The potential flow safety issues arising during the transport process, such as the blockage of pipelines and equipment, have attracted considerable attention. This study aims to investigate the impact of hydrate adhesion features, including agglomeration, cohesion, and deposition, on the flow transport processes in solid fluidization exploitation and to provide a reference for the design and application of multiphase hydrate slurry transport in solid fluidization exploitation. We established a numerical simulation model that considers the hydrate adhesion properties using the coupled computational fluid dynamics and discrete element method (CFD-DEM) for the multiphase mixed transport in solid fluidization exploitation. An appropriate model to simulate the adhesion force of the hydrate particles and the corresponding parameter values were obtained. The conclusions obtained are as follows. Under the same operating conditions, a stationary bed is more likely to form in the transport process due to the hydrate adhesion forces; adhesion forces can increase the critical deposition velocity of the mixture of hydrate particles and cuttings. Hydrate adhesion lowers the height of the solid-phase moving bed, while the agglomeration and cohesion of particles can intensify the aggregation and deposition of hydrate debris and cuttings at the bottom of the pipe. These particles tend to form a deposit bed rather than a moving bed, which reduces the effective flow area of the pipeline and increases the risk of blockage.

For reservoirs with abnormally high pressure and high geostress, formation resistivity can be greatly affected. This increase of resistivity resulting from high stress causes errors in the identification of reservoir fluids. In order to investigate the effect of stress on resistivity, resistivity measurement was conducted simultaneously with triaxial testing to obtain rock resistivity under high temperature and high pressure. The changes of resistivity and resistivity increasing coefficient with horizontal differential stress and minimum horizontal stress were revealed from experiments. Besides, field data were analyzed to show the main influencing factors of formation resistivity under reservoir conditions. In addition, a new resistivity correction model for high geostress formation was derived in this work. The interpretation results are in good agreement with well testing data in the Keshen area of the Tarim oilfield, China.

The present work studies the influence of oil pipe joint passing through annular blowout preventer (BOP) on its sealing performance in high pressure gas wells under snubbing service. When the oil pipe joint passes through the BOP, due to the change of its structure, it is easy to cause the rubber core seal failure of the BOP, resulting in the leakage of toxic and harmful gas in the well, which seriously threatens the safety of the operators. Aiming at the problem of gas leakage caused by rubber core seal failure of annular BOP, based on the rubber large deformation theory and rubber core seal mechanism, a dynamic finite element model of rubber core-oil pipe joint is established, and the correctness of the model is verified by comparing the failure of rubber core on site; The results show that when the oil pipe joint passes through the BOP, a sealing buffer zone (SBZ) will be formed at the upper and lower shoulder of the joint, and the contact stress of the rubber core will decrease by 10 MPa-30 MPa; Because of the funnel effect of the rubber core, the damage of the rubber core caused by the running oil pipe joint of the BOP is greater than that caused by the lift oil pipe joint; When lifting oil pipe, the existence of SBZ is easy to cause gas leakage in the well; The optimized structure of oil pipe joint with small inclination and long shoulder can significantly reduce the influence of SBZ on the sealing performance of BOP. The research work in this paper is of great significance to improve the dynamic sealing performance of BOP.

Based on corrosion thermodynamics and kinetics, considering the multi-field coupling effects of fluid flow, electrochemical reaction and mass transfer process, a new corrosion prediction mechanistic model was proposed by introducing the influence factor of corrosion product film on diffusion coefficient of ion mass transfer, which is based on the CO₂ corrosion prediction model proposed by Nesic et al. The influence of temperature, flow rate and pH value on CO₂ corrosion behavior on 20# steel was studied by orthogonal tests. Scanning electron microscopy (SEM) and energy spectrum analysis (EDS) was used to analyze the surface and cross section morphology of the corrosion product film, and the thickness of the corrosion product film was measured. The results show that the introduced influence factor can simplify the ion mass transfer calculation in the presence of corrosion product film, and the relative error between the predicted value of the modified model and the experimental results is satisfactorily controlled less than 10%. Compared with the prediction model without considering the influence of corrosion product film, the influence factor can effectively correct the high prediction value of the mechanistic model under the influence of corrosion product film, improve the accuracy and applicability of corrosion prediction, and provide important theoretical guidance for the design, manufacturing, operation and maintenance of oil and gas production pipelines and related facilities.

API standard threads are the most commonly used thread configurations for drill pipe joints in the petroleum industry. Recently with the increasing application of horizontal wells and extended-reach wells in drilling engineering, drill pipe joint threads are subjected to complex loads, and drill pipe joint thread breakage accidents occur frequently. The API NC38 threaded pair used in the SU36-8-4H2 well suffered a fracture accident. Macroscopic analysis found that the fracture sites were located near the root of the first engagement pin-thread where the stress was greatest. Therefore, it is necessary to find an alternative method to reduce the largest stress of NC38 threads. Then, a new design method of unequal taper thread (UTT) pairs is proposed that the taper of pin thread, slightly smaller than the taper of matched-box thread, is not equal to one of box-thread. In the UTT pairs of API NC38 thread, the taper of box thread is kept as the standard taper of 1:6, but the taper of pin thread is, respectively, 1:6.1 (UTT-I), 1:6.2 (UTT-II), 1:6.3 (UTT-III) and 1:6.4 (UTT-IV). The 3D finite element models of four UTT pairs and one standard pair based on NC38 thread were developed, and the mechanical properties of five thread pairs bearing such typical working loads as torque, axial compression, axial tension, bending moment, internal and external pressure, were analyzed. The results show that four UTT pairs are superior to the standard pair of API NC38, and UTT-III has the most performance in all of four UTT pairs. Compared with the standard pair of API NC38, UTT-III pair can improve the bearing capacity such as torsion strength, compression strength, tensile strength, bending strength, strength against internal and external pressure, by 24.8%, 13.2%, 22%, 9.99% and 14.2%, respectively. The new design method of UTT pair enhances the bearing capacity of API NC38 thread, and has been applied in Changqing Drilling Company of CNPC Chuanqing Drilling Engineering Company Limited. The UTT-thread pair method is not only applicable for API series threads to improve the connection performance, but also suitable for various non-API taper connection threads to promote existing working ability such as air tightness, stress corrosion resistance, fatigue resistance et al.

Hydraulic fracturing (HF) is a commonly used technique to stimulate low permeability formations such as shale plays and tight formations. However, this method of well stimulation has also been used in high permeable unconsolidated sandstone formations to bypass near-wellbore formation damage and prevent sand production at some distance apart from the wellbore wall. The treatment is called frac-pack completion, where a short length but wide width fracture is formed by injecting aggressive concentrations of proppant into the fracture plane. This operation is known as tip screen-out (TSO). Detailed design of fluid and proppant, including an optimal pump schedule, is required to achieve satisfactory TSO. In this study, we first assess the lattice-based numerical method's capabilities for simulating hydraulic fracturing propagation in elastoplastic formation. The results will be compared with the same case simulation results using a pseudo 3D (P3D) model and analytical model. Second, we explore the Nolte (1986) design for frac-pack and TSO treatment using lattice-based software and the P3D model. The results showed that both models could simulate the hydraulic fracturing propagation in soft formation and TSO operation, while some differences were observed in generated geometry, the tip screenout time and net pressure profiles. The results are presented. It was noted that fracture propagation regime (viscosity/toughness), nonlocality and nonlinearity had an influence on the different geometries. The advantages of each model will be discussed.

A major cause of some of serious issues encountered in a drilling project, including wellbore instability, formation damage, and drilling string stuck -which are known to increase non-productive time (NPT) and hence the drilling cost -is what we know as mud loss. The mud loss can be prevented or at least significantly reduced by taking proper measures beforehand provided the position and intensity of such loss can be properly predicted using an accurate predictor model. Accordingly, in this study, we used the convolutional neural network (CNN) and hybridized forms of multilayer extreme learning machine (MELM) and least square support vector machine (LSSVM) with the Cuckoo optimization algorithm (COA), particle swarm optimization (PSO), and genetic algorithm (GA) for modeling the mud loss rate based on drilling data, mud properties, and geological information of 305 drilling wells penetrating the Marun Oilfield. For this purpose, we began by a pre-processing step to attenuate the effect of noise using the Savitzky-Golay method. The whole set of available data was divided into the modeling (including 2300 data points) and the validation (including 483 data points) subsets. Next, the second generation of the non-dominated sorting genetic algorithm (NSGA-II) was applied to the modeling data to identify the most significant features for estimating the mud loss. The results showed that the prediction accuracy increased with the number of selected features, but the increase became negligible when the number of selected features exceeded 9. Accordingly, the following 9 features were selected as input to the intelligent algorithms (IAs): pump pressure, mud weight, fracture pressure, pore pressure, depth, gel 10 min/gel 10 s, fan 600/fan 300, flowrate, and formation type. Application of the hybrid algorithms and simple forms of LSSVM and CNN to the training data (80% of the modeling data, i.e. 1840 data points) showed that all of the models tend to underestimate the mud loss at higher mud loss rates, although the CNN exhibited lower underestimation levels. Error analysis on different models showed that the CNN provided for a significantly higher degree of accuracy, as compared to other models. The more accurate outputs of the hybrid LSSVM model than those of the simple LSSVM indicated the large potentials of metaheuristic algorithms for achieving optimal solutions. The lower error levels obtained with the CNN model in the testing phase highlighted the excellent generalizability of this model for unseen data. The more accurate predictions obtained with this model, rather than the other models, in the validation phase further proved this latter finding. Therefore, application of this method to other wells in the same field is highly recommended.