Residual oil saturation (Sor) is defined as fraction of pore volume occupied by oil at the end of the oil displacement by a specific fluid. It signifies the ultimate recovery under a given displacement process and represents the endpoint of the relative permeability curves in reservoir simulation. The estimation of Sor is critical in understanding the behavior of the reservoirs during various recovery mechanisms and it is a very important measure used to decide the EOR process selection and feasibility for further exploitation of the reservoir.
The residual oil saturation varies depending on lithology, pore size distribution, permeability, wettability and fluid characteristics. There are several ways to estimate the Sor including core analysis methods, well log methods, and other saturation and volumetric assessment methodologies. However, none of the methods is regarded as a single best method for determining the Sor. In addition, there could be circumstances that the remaining oil saturation (ROS) is misinterpreted as Sor. The integration of various data sources is therefore critical in estimating the true residual and remaining saturations.
This paper highlight number of offshore field case studies where significant difference observed in Sorw estimation using various approaches from core and logs analysis. In these examples, SCAL data and logs in hydrocarbon column as well as swept intervals together with the wells/reservoir performances have been considered in estimating the Sor. It was observed that the production forecasting, reserve estimates, EOR mechanism are hugely affected by the Sorw estimation.
ASP flooding is proven a great success in China due to its large number of field tests and incredible oil production. Latest progress of ASP flooding field tests and application in China is summarized. Incremental oil recovery of ASP flooding can be as high as 30%, much higher than all the other chemical enhanced oil recovery (CEOR) techniques. Although one recent surfactant-polymer flooding (SP) field test is reported 18% incremental oil recovery, other SP flooding field tests are not so successful. More incremental oil recovery does not always ensure more economic benefits. With progress of surfactant production technology in Daqing, alkali NaOH was finally proven better than Na2CO3. Too high polymer concentration may block low permeability strata. The allowable maximum polymer parameter (molecular weight and concentration) is key to success, especially when emulsification is taken into consideration. There is no one-fit-all ASP formulation and the dynamic adjustment is necessary in ASP flooding. Why pre-slug is used is still worth investigation. The average cost of ASP flooding can be lower than SP flooding due to more oil produced.
Globalization inevitably drives prices of commodities and services lower. As such, to remain competitive in the Oil & Gas industry it is imperative in low oil prices regimes to decrease operating costs. A key element of low operating costs in hydrocarbon exploration, production and refining, is corrosion control. In this paper the development of corrosion circuits/loops is improved by categorizing sixty four damage mechanisms based on operating preconditions, material susceptibility and monitoring methods. The inspection resource requirements are determined for each Refinery unit based on number of damage mechanisms, the required monitoring methods and the screening of regulated equipment. Corrosion loops are developed based on failure mechanism applicability and not arbitrarily changes in operating conditions or the probability of failure. Material selection methods for critical units during detailed design should not be qualitative to avoid over/under designs that are carried over to operating/inspection programs. When inspection effectiveness does not add significant value to risk reduction due to a gap between operating requirements and turnaround intervals, consequence mitigation, including operating practices should be examined. Therefore, risk studies including RCM, HAZOP and QRA should be aligned with RBI and validated by failure and consequence statistics. IOW assignment should consider design risk profile and operating (operations and inspection) risk profiles. By far this is the underlining reasons why operators are unable to leverage management systems to mitigate risk, lower operating cost and avoid major accidents. The importance of managing risk transfer between equipment design, operation, inspection, safety and system integration is highlighted. Integrity operating windows are not exclusive. The alignment of all the installation risks enables the operator to leverage risk profiles in manner that satisfies the statutory body and addresses its business needs.
Primary recovery of heavy-oil is remarkably low due to high viscosity and low energy by solution gas exsolution to drive the oil. Gas injection to improve foamy flow and also to dilute the oil in such reservoirs has been proposed as a secondary recovery method. However, because of the high costs of injected gases, efforts are needed to optimize the process by selection of proper gas type (or gas combinations) and suitable injection scheme. To achieve this goal, an experimental procedure was followed with rigorous analyses of the output. A 1.5 m long and 5 cm diameter sand-pack was first saturated with brine, which was replaced with dead oil. Then, gas solvents were injected to dead-oil containing core-holder until nearly reaching 500 psi followed by a two-day soaking period. Pressures all along the sand-pack were recorded with eight pressure transducers. Different combinations of various gas solvents (methane, CO2, and air) aiming to select the most competitive and economic formula were tested with a certain set of pressure depletion rates.
The physics of the foamy oil flow for different solvent mixtures and depletion conditions were analyzed using pressure profiles acquired, recorded oil/gas data with time, and gas chromatography and SARA analyses of the produced gas and oil. Three huff-n-puff cycles were applied. Compared with other light hydrocarbon solvents and carbon dioxide, air has its high advantage in terms of accessibility and lowered cost. Hence, attention was given to air that was mainly used to pressurize the system and increase oil viscosity due to oxidation process with an expectation of better foam quality when injected with other gases such as CO2 and methane. Methane (CH4) yielded the quickest response in terms of gas drive but, in the long run, CO2 was observed to be more effective technically. Air was observed to be effective if mixed with CO2 or methane from an economics point of view. To sum up the results, air Huff-n-Puff (HnP) followed by 2-cycles of CH4 HnP yielded 36.21% recovery, while air HnP followed by 2-cycles of CO2 HnP delivered 30.36% oil. When the gases are co-injected, air 50%-CO2 50% and air 50%-CH4 50% recovered 29.85% and 23.74% of total oil-in-place, respectively.
The intermediate phase on South Mahakam (SMK) field presented technical and economical challenges due to multiple bit runs, attributable to thick carbonates with Unconfined Compressive Strength (UCS) up to 30K psi. The typical phase is either 12-1/4" or 8-1/2", reaching 1600m long with 90% containing the carbonates. Initially, different configurations of 8-1/2" Polycrystalline Diamond Compact (PDC) bits with durability in mind were selected but failed to deliver performance with more than 1 run required. Poor post-run dull gradings were observed reflecting broken/worn out cutters, and even blades ring out.
A recent campaign on SMK introduced two new 12-1/4" bit designs. First, a Hybrid bit (Roller Cone – Fixed Cutter PDC) was selected following a positive global experience on hard formations. A second trial involved a PDC with a Conical Diamond Element profile in the secondary cutter row – aimed to deliver high loading point to fracture hard formations and ease drill out. Both designs managed to drill the section in 1 run and delivered record speed.
The Hybrid bit managed to deliver at an almost double Penetration Rate (14.9 m/hr) than previous runs. Its durability was however limited by the seal life of the Cone. During run, a real-time monitoring of parameters and Minimum Specific Energy (MSE) was performed to detect for failures. Despite the precautions, a seal was damaged and the bit was undergauged. A control trip was triggered eliminating the cost saved for drilling in 1 run.
Conversely, the PDC with secondary conical elements delivered higher performance (29.6 m/hr) with dull grading allowing for a re-run under the same conditions. The bit became the standard for SMK, continuously delivering the phase in 1 run, a saving of 5 days.
This paper will analyze the cause of the Hybrid bit damage and how parameters monitoring did not pick up failure signals. It will also highlight the success of the bit conical elements in terms of practicality and effectiveness for drilling hard carbonates in SMK.
Malik, Ankit (BG Exploration and Production India Ltd) | Prakash, Ravi (BG Exploration and Production India Ltd) | Kumar, Mukesh (BG Exploration and Production India Ltd) | Barot, Miten (BG Exploration and Production India Ltd)
Liquid loading of oil and gas wells occurs when the reservoir fails to deliver hydrocarbons to the surface due to accumulation of liquid in the well. In Oil reservoirs with gas cap and aquifer, liquid loading post shutdown revival of oil wells with high gas liquid ratio (GLR) is poorly understood and documented. The mechanism and prediction of onset of such liquid loading has been studied and discussed in this paper.
The field observation of loading of high GLR oil wells could not be explained with steady state analysis in a mature carbonate offshore field. Transient analysis successfully revealed liquid loading as observed in field. However, correct set up of initial conditions is imperative for prediction using transient analysis method which is discussed in this paper. A workflow has been developed to predict onset of start-up liquid loading and to build in risking using a risk matrix incorporating relevant well parameters. The methodology was used to estimate the gas lift requirement and associated risked reserves.
The liquid loading of high GLR oil wells after a brief period of shutdown has been successfully modelled using transient method by representing correct initial conditions. However, ability of well to re-deliver gas at the steady state GLR value during the start-up is an uncertainty. Hence, an element of risking has been captured to predict the most likely time of start-up loading using a risking criterion based on individual well's flow parameters.
The results from the above methodology of prediction and risking show that wells are susceptible to liquid loading much in advance as predicted from steady state workflows which matches with the field observed well performance. This has a significant impact on the lift gas flowrate and top side infrastructure required to sustain flow from these wells. The paper also discusses a strong business case to evaluate liquid loading from predicted parameters at field development planning stage using the proposed workflow to secure future well production and save on additional costs of retrofitting gas lift infrastructure.
Musa, M. Nizar (Petronas Carigali Sdn Bhd) | Ismail, W. Rokiah (Petronas Carigali Sdn Bhd) | Roh, Cheol Hwan (Petronas Carigali Sdn Bhd) | Zulkifli, Shahrul Anwar (Petronas Carigali Sdn Bhd) | Hui, Nicholas Foo Kwang (Petronas Carigali Sdn Bhd) | Jackson, R. (3M Ceramics) | Gundemoni, B. (3M Ceramics) | Barth, P. (3M Ceramics)
The current state of oil and gas economics has emphasized focus in managing and optimizing production from mature fields. It is estimated that 70% of the world's oil and gas production are contributed by mature fields. However, sand production is inevitable as the pressure declines and water breakthrough take place. Clastic reservoirs with unconsolidated formation sand compelled with moderate and high permeability are prone to produce sand under the said conditions. In gas environment, conventional sand control demands for an expensive investment as high gas velocity increase the chances of erosion at downhole equipment. Moreover, gas reservoirs have always been an integral part Malaysia's oil and gas business. As the portfolio expands to cater for the regional energy demand, focus on fit for purpose sand control in gas wells is crucial in ensuring continuous production delivery to customers. As a current practice, sand production has been handled by standalone metal screens or combined with gravel packing. One of the cheaper options available in the market is the ceramic sand screen that allows for rigless installation while providing durable material that is susceptible to erosion caused by high gas velocity for a continuous production as the ceramic material is 10 times harder than steels (Jackson et al., 2015) and it is more susceptible to corrosion in comparison to steels (Wheeler et al., 2014).
This paper will focus on the revival strategy of a gas well with a currently damaged screen due to erosion. Depending on the current well completion profiles, the assessment includes the selection of screen length, size of screen slots, support assemblies' identification and design; and actual installation sequence and methodology in ensuring safe and successful deployment of ceramic sand screen downhole. As the first through tubing application in a gas well for Asia Pacific, assessment on the first foray in Malaysia's market is worthwhile in ensuring feasibility of applications in Malaysia's gas wells. The study and assessment will provide future reference for superior downhole sand control option in gas wells.
As technology advances in horizontal well drilling, long horizontals completion are now preferred for producers aiming to explore more oil-bearing zones, especially in heavy or tight oil reservoirs. However, for strong waterdrive horizontal wells, abrupt increase of water-oil ratio and abounding unwanted water production severely affect the profitability of the field due to the constant decrease of oil production and premature well shutting.
The targeted reservoir of this work is a typical heavy oil reservoir with strong waterdrive. By December 2014, the average water cut for the two productive layers has increased 40-70%, for some wells especially, the water cut has exceeded 95% causing frequent well shutin. Therefore, to ensure the productivity of the horizontal wells, water shutoff has become a challenging and urgent task.
According to the aquifer identification and water influx diagnosis, 27 horizontal wells distributed in aforementioned two productive layers were first categorized into two groups in order of treatment difficulties, after which foam-assisted gel and gel treatments were designed and conducted.
For the three of the treated wells, the average water cut was significantly reduced from 80.3% to 48.0%. Although the gross liquid production rates were slightly reduced after treatment from 31.7 to 27.7 t/d, the oil production rate was considerably increased by 28.1 t/d. By January 2016, 4 500 t of the incremental oil was produced indicating the success of the water shutoff jobs. However, it should be noticed that the water cut of the N2 foam-assisted gel treated well started to rapidly rise after two months. This is probably caused by inappropriate foam/gel volume ratio. The water control strategies and field results in this heavy reservoir will provide the necessary clues for the design and application of water shutoff treatments for horizontal wells driven by strong water.
Ren, Jinheng (China University of Petroleum) | Wang, Yanling (China University of Petroleum) | Jin, Jiafeng (China University of Petroleum) | Wang, Kun (China University of Petroleum) | Guo, Baoyu (Drilling Engineering and Technology Company, Shengli Petroleum Engineering Corporation Limited of SINOPEC) | Wang, Xudong (Gomado Fosterand CailiDai, China University of Petroleum)
Due to the significant difference of water-in-oil emulsion and oil-in-water emulsion in viscosity, conductivity, rheology, thermal resistance, emulsion system has been widely used in the development of oil fields. The reversible phase inversion technique can enhance the performance of emulsified working liquids during the transportation of fluids in porous media. The objective of this study is to study the preparation and the application of the reversible emulsion controlled by inorganic salts.
SDBS, SDS, and SPS were used as emulsifiers in this study. The white oil and deionized water were emulsified into anoil-in-water emulsion by high-speed stirring. Multivalent metal cations were added to the emulsion to control the inversion of the emulsion to water-in-oil type. Then, the multivalent metal cations were removed by anions, leading to the emulsion reversed from water-in-oil to oil-in-water type. The stability of emulsions was evaluated by the stratification time, thermal resistance, conductivity, emulsion-breaking voltage and microstructure.
The results showed that emulsion's dehydration rate was 8.1% at 25°C, which increased to 14.3% as the temperature reached 90°C after 5 hours. The average diameter of droplets was about 6 μm and conductivity was about 619 μs·cm−1. The emulsion processed by CrCl3·6H2O solution inverted to water-in-oil type, and its oil separation rate was 11.9% at 25°C and 18.2% at 90°C after 5 hours. The emulsion-breaking voltage and average diameter of droplets were 153 V and 13 μm, respectively. After Cr3+ was removed by Na2CO3 solution, the type of emulsion became oil-in-water againand the dehydration rate of this emulsion increased from 3.2% to 5.8% when the temperature reached up to 90°C. Under this circumstance, the average diameter of droplets was 5 μm and conductivity was 1907 μs·cm−1. The emulsion was of high stability before and after inversion.
The emulsion controlled by inorganic salts can be reversed between oil-in-water and water-in-oil type efficiently, which can be used as emulsifier within drilling fluid in the low-permeability reservoir. The characteristics of reversible emulsion drilling fluid include inhibition for shale rock, good lubricity, thermal stability, and excellent cementing quality.
Lichen, Zheng (Research Institute of Petroleum Exploration and Development, PetroChina) | Jiaqing, Yu (Research Institute of Petroleum Exploration and Development, PetroChina) | Yucai, Wang (PetroChina Jilin Oilfield Company) | yang, Gao (Research Institute of Petroleum Exploration and Development, PetroChina) | Xiaohan, Pei (Research Institute of Petroleum Exploration and Development, PetroChina) | He, Liu (Research Institute of Petroleum Exploration and Development, PetroChina)
The rapid progress in fracturing technology pushes the oilfield development to bigger scale, The traditional Multi-stage fracturing technology such as ball fracturing, quick drillable bridge plug fracturing have problems like limited fracturing stages, high operation risk and high later operation cost etc. Multistage fracturing technology based on Radio Frequency Identification (RFID) was developed, it overcomes the shortcomings of traditional fracture tools, but the low tag recognition rate, speed limitation and complicated structure limit its further application. A new generation active tag control Sliding sleeve Fracture tool is developed. This fracture tool is composed of vacuum energy storage system, electric control direction valve, sliding sleeve, microcomputer control system, battery group, RFID antenna and active tag. The vacuum energy storage system provide power for the open and close of the sliding sleeve, the operating pressure is the union of the surface fracture pressure and the head of the liquid, which can be controlled on the ground. Electric control direction valve controls the oil flow direction and control the opening and closing of the sliding sleeve. The antenna works only in low power mode and picks the signal from the active tag. The active tag ball contains micro battery inside and signal producing system, it will be wake up by a special instrument before lower into the well, the battery will sustain the tag work for at least 30 minutes. The active tag signal can be picked up by the antenna at 100% success ratio and without speed limitation. During the fracturing process, the active tag will be dropped in the well to control the opening and closing of the sliding sleeve in any specific fractured interval. After fracturing, pressure wave is applied to open all the sliding sleeves and the production operation begins. Compared to the first generation RFID control sliding sleeve, the Active tag control sliding sleeve has relative simpler structure, more compact dimension, longer battery service life, more reliability and control flexibility, which is more suitable for the oil field fracture application. The active tag signal transfer mechanism improve signal transfer reliability greatly and without speed limitation, which lowers the power consumption of the antenna and will provide long battery service life, the vacuum energy storage system simplify the structure greatly and the sleeve active pressure can be controlled on the ground.