Jin, Fu (CNPC Drilling Research Institute) | Shunyuan, Zhang (CNPC Drilling Research Institute) | Bingshan, Liu (CNPC Drilling Research Institute) | Weiwei, Yin (China United Coalbed Methane Corporation, Ltd.) | Chen, Chen (CNPC Drilling Research Institute)
It is estimated that tight oil takes up 46% of the total reserve volume, including conventional tight oil, super-tight oil and ultra-tight oil whose viscosity is 5.8×104mPa·s (degassed crude oil at 50°C). Some tight oil resources are 600-900m deep, while others are found in deep formations (1300-1700m). In order to deal with sand production and low recovery rate integrated researches on super-tight and ultra-tight oil buried in deep formations have been accomplished.
A group of 7 wells were selected and the overall steam stimulation was simulated by software. All modified chemicals such as the high temperature frothers, high temperature gel particle plugging agents and special resins were tested in labs in order to prove their performance, while downhole tools had been applied in adjacent wells. At last the average sweep efficiency and oil production rate of wells in the group were compared with that of adjacent wells.
Casing programs, horizontal sidetracking technologies and slim hole cementation technologies shall be optimized to extend the well's life. The multi-well steam stimulation technology which depends on injecting steam into a group of wells and creating a uniform temperature field is useful, as steam channeling caused by longitudinal heterogeneity in the tight oil reservoir and repetitive steam injection may be overcome. Mechanical interval selection technology and vacuum heat insulation pipe are recommended to obtain steam of appropriate volumes. Various high temperature frothers and gel particle plugging agents shall be applied to adjust the steam injection and production profile, improving the sweep efficiency. Liquefied carbon dioxide and other cleanup additives may be injected before steam as more water comes out and remaining oil keeps farther away from the borehole after repetitive steam huff and puff. Fracturing and sand exclusion may be achieved at the same time by squeezing special resins into formation while fracturing. Sand may be controlled by artificial boreholes, optimized liners and flushing foams. Series of drilling and production technologies have been optimized, therefore the average sweep efficiency and recovery rate of single wells in the group were improved by 12.52% and 13.23% respectively.
Conventional steam stimulation used to be adopted by scale in Block CH, while the daily production rate began dramatically decreasing after 4 to 5 rounds of steam injection. The integration of multi-well steam stimulation technology, mechanical interval selection technology, vacuum heat insulation pipe running technique and optimization of chemicals and gases improves heat utilization and sweep efficiency. While the optimized drilling and completion technology improved the quality of horizontal wells.
Jin, Fu (CNPC Drilling Research Institute) | Shunyuan, Zhang (CNPC Drilling Research Institute) | Bingshan, Liu (CNPC Drilling Research Institute) | Chen, Chen (CNPC Drilling Research Institute) | Shifei, Dong (Daqing Oilfield Huayu Industrial Company) | Weiwei, Yin (China United Coalbed Methane Corporation, Ltd.)
SAGD technology has been applied by scale in Liaohe Oilfield China, where high pressure steam is injected in a horizontal well to drain tight oil into the lower production well. However, much waste heat has not been exploited, including heat of the hot production fluid, flue gas and HPHT brine separated by the steam-water separator in the boiler.
On-field researches were carried out on many dual-horizontal wells in Liaohe Oilfield to learn the present operation situation and technical capabilities, while thermodynamic models of various types were established and experimental apparatuses were utilized to analyze the present thermal distribution and each of the above waste heat sources. Effects of various media, flow rates and temperatures on heat utilization and the heat deficit rate were studied on the assumption that 1t crude oil was produced each hour.
The high temperature production fluid may be used to heat water in the boiler first and then used as the heat source of the absorption heat pump, so that heat is transferred from the low temperature heat source to the high temperature heat source and the low grade heat energy is recycled. Waste heat of flue gas may be utilized to help combust air and the thermo-coil may be used as the air preheater, which improves boiler's heat efficiency. As a high grade waste heat, the HPHT brine separated from moist steam in the boiler takes up 20% of the total water and shall not be only used to heat injected water. Instead, it may be used to achieve flash evaporation. Thus, waste water is heated and distilled water is recycled.
The optimized waste heat recyling proposal applies the thermo-coil air preheater to recycle flue gas, flash evaporated hot brine to evaporate waste water and high temperature production fluid to heat boiler water. On a basis of the same fuel consumption volume the recovery rate of crude oil is enhanced by 31% and marketability of it is improved by 8.6%. More energy is saved and recycled, which contributes to the green oilfield construction.
Al-ibrahim, Abdullah (Kuwait oil Company) | Al-Bader, Haifa (Kuwait oil Company) | Al-Nabhan, Abdul Razzaq (Kuwait oil Company) | Packirisamy, S. (Kuwait oil Company) | Sagar, D. Vidya (Kuwait oil Company) | Manimaran, A. (Kuwait oil Company) | Ibrahim, Anwar (Kuwait oil Company) | Al-Ateeq, Abdulla (Kuwait oil Company)
To reduce flaring of produced hydrocarbon during well testing operations in order to protect the environment, comply with safety regulations and conserve oil.
During well-testing operations the produced hydrocarbon is usually flared in the open flare pit. As per the existing company's HSE procedures, flaring during well testing is considered as a safe option. However, flaring activities needs to be minimized or eliminated as some wells are located in environmentally sensitive areas which are close to farms, Highways or camping area. Due to location constraints the flaring should be minimized to the possible extent. As the well is exploratory, the well was not connected yet to the production facility. The only means of oil transportation will be by using road tankers, for that the H2S concentration in oil needs to be reduced to a permissible limit.
The heavy oil well to be tested contains H2S concentration up to 22 %(220,000 ppm) in gas. A novel process was initiated to eliminate/minimize flaring during well testing operations. H2S scavenger technology was selected for field trial to convert the produced sour liquid to be suitable for transportation through vacuum tankers to the nearest production facility. Accordingly H2S scavenger chemical was arranged and well test surface layout was modified with additional chemical dosing points. After separating the gas from oil using surge tank and separator dosed H2S Scavenger into oil line. This exercise resulted in ensuring that the H2S concentration in treated oil is at a permissible limit and the oil is suitable to be transported using road tankers.
Field trail was implemented in sour heavy oil well to evaluate the feasibility of using H2S scavenger chemical to mitigate/minimize high H2S concentration in the produced fluid. Two heavy oil wells (17-200 API) were tested with this process and H2S content in oil was reduced to almost 15 ppm. Achieved economical H2S scavenger treatment cost of $18/bbl for reducing H2S in oil from 600 ppm to 15 ppm. Oil flaring was eliminated and only small quantity of the produced sour gas (0.001mmscfd) was flared safely through flare stack. Approximately 5,500 bbls of crude oil were produced from an exploratory well and safely transported by road tankers to nearby production facility during two weeks of testing period. For the first time in Kuwait an exploratory sour heavy oil well was successfully tested without flaring oil.
The innovative solution of using H2S Scavenger during testing the sour well had eliminated flaring of crude oil which avoided environmental pollution and conserved the produced oil. This success proves that sour heavy oil wells can be tested safely without flaring oil and paves the way for implementing this novel concept in future applications.
Effective exploitation of deep and heavy oil reservoirs is a strategic objective for KOC. It is observed that suitable mode of artificial lift is required to produce these reservoirs. Objective of present work, is to evaluate diverse challenges, offered by various artificial lift methods, to produce these reservoirs. Scope of work includes selection of appropriate artificial lift technology along-with suitable production methodology, to facilitate sustained production from these reservoirs.
This study is carried out for representative deep and heavy reservoir of KOC. Perforation zone is at 9300 feet. Viscosity of well-fluid is 7800 centipoise at reservoir temperature of 190°F. API gravity of well-fluid is 10. It is known that well-fluids can flow to the well-bore; but cannot flow to the surface. Analysis of various artificial lift systems, such as, Gas Lift, SRP, PCP, ESP and Jet Pump, is carried out, with reference to the available well data and field operational constraints. Study also encompasses need for any other technology, which is required along-with artificial lift, to produce this reservoir.
It is observed that it is not possible to use either SRP or PCP because both have limitations, to operate, at high depths. It is not possible to employ gas-lift, due to constraints related to availability of injection gas. ESP and Jet Pump, are the only two technically feasible lift modes.
It is perceived that ESP is more suited than Jet Pump, with regard to the issues, like, cost, operational ease, surface foot-print and HSE. However, with regard to our simulation studies, it is observed that it is not possible to produce this reservoir, with ESP alone because due to high viscosity of well-fluids. Therefore, use of downhole heater below down-hole ESP or continuous injection of suitable viscosity reducer, below down-hole ESP, is considered. Either of this, add-on utility can help to reduce viscosity of well-fluids, to such an extent; wherein, it is possible for down-hole ESP, to lift well-fluids up to the surface.
Study also entails laboratory work, which is carried out to select suitable viscosity reducer, with reference to the oil sample of this reservoir. It is concluded from simulation studies that target rate of 500 b/d can be achieved with ESP, to produce this reservoir, provided it is backed-up by proper mechanism, to reduce viscosity of well-fluids, before well-fluids enter into the pump.
Study has adequately addressed challenges, offered by various artificial lift modes, to produce deep and heavy oil reservoirs. It is also inferred from the studies that coherent integration of suitable lift system with other compatible technologies, is essential, to achieve sustained production from this reservoir. The study constitutes crucial benchmark for us, to decide future production strategy to exploit similar reservoirs. The study can serve, as a useful reference guide, for exploitation of deep and heavy oil reservoirs, of comparable nature.
Heavy oil (HO) is often produced with Enhanced Oil Recovery (EOR) methods such as steam or water flooding. In addition to flood front movements reservoir seal integrity has become an issue. Seal integrity is best addressed with microseismics and water flood front bets with electromagnetics. We address the fluid imaging problem using electromagnetics and after careful 3D feasibility and noise tests. We selected Controlled Source Electromagnetics (CSEM) in the time domain as the most sensitive method. From the 3D modeling we derived as key requirement that borehole and surface data needed to be integrated by measuring between surface to borehole and also calibrated using conventional logs.
Depending on the resistivity contrasts between the reservoir and the surrounding formation we need to measure electric AND magnetic fields as each of them have different sensitivity. The magnetic field senses more conductive strata, while the electric field will define fluid changes inside the HO reservoir. Furthermore, for shallow reservoir multi-frequency band sensors need to be deployed to get the optimum sensitivity.
Over the last decades we carried out 3D feasibilities for many oil fields and we are presently conducting the FIRST steam flood Pilot in an oil field in Asia. We also design custom data acquisition system for land, marine and borehole. Carrying out a Feasibility for each reservoir is key to control risk and cost. 3D modeling allows to integrate complex nature of the reservoir by constraining the model with existing seismic data. In all hydrocarbon cases it shows the need for full tensor CSEM, surface and borehole measurements to effectively determine the HO/steam flood front.
For light and medium crude oil produced waters, the compact flotation unit (CFU) technology has been widely used as the final cleaning step in the process during the last 10 years, especially in Europe. In general, more traditional methods such as induced gas flotation (IGF) and dissolved gas flotation (DGF) are more commonly applied on heavy crude oil-produced waters. The CFU technology has been preferred over the more traditional technologies due to substantially reduced weight and footprint combined with superior cleaning efficiency.
This paper describes efforts related to examining the effectiveness and applicability of using CFU technology in heavy crude oil produced water (PW) polishing and comparing the results with polishing produced water from light and medium crude oil. Experimental work was conducted in a water test setup in which synthetic produced water with different crude oils (13.7–39.7° API gravity) was tested for flotation efficiency using a proprietary compact flotation unit. A literature study was performed to support the experimental results. Furthermore, field data were collected from field trials using the proprietary compact flotation unit technology with produced water containing crude oils in the 17–43° API gravity range.
Experimental results showed that for a given crude oil type, the oil removal efficiency is dependent on oil droplet size, and these results are supported by the literature. Comparing different API gravity crude oils with the same droplet size showed, in general, a slightly reduced flotation efficiency with increasing gravity, which could be explained by the correlation between increasing gravity and increasing coverage time.
However, field data for 17–43° API gravity crude oil show the ability for the proprietary compact flotation unit technology to meet normal effluent requirements (≤ 25 ppm) over the full API gravity range. Field data further emphasizes the importance of preparing optimum process conditions for the flotation unit.
Despite of the low retention time compared to traditional IGF and DGF technology, the compact flotation technology has proven to be robust for heavy-oil treatment. This result is partially explained by the fact that induction and coverage times are shorter in turbulent flow regimes than in traditional laminar flotation environments. Furthermore, the proprietary compact flotation unit technology combines both induced and dissolved flotation with vessel internals that effectively minimizes the rise path.
It should be emphasized that these findings relate to the examined CFU models only because the various models have different technologies that will lead to different performances.
Previously published models for predicting heavy oil viscosity based on the composition or API gravity are extensively evaluated to ascertain their effectiveness with 28 newly collected Kuwaiti heavy oil samples from different locations. The composition of each sample is determined, and its viscosity is measured at atmospheric pressure across a wide range of temperatures (20–80 °C), resulting in 196 data points. The measured viscosities are used to evaluate existing models based on the principle of corresponding states, the residual viscosity concept, and an equation of state (EOS). As all of them failed to accurately predict the Kuwaiti heavy oils being studied, a new compositional model is developed to overcome their inherent limitations. This new model provides a good prediction of the viscosity of Kuwaiti heavy oils, with an average relative error of 3.8%. In addition, it is much simpler and easier to use than existing methods when applied to Kuwaiti crudes.
Some key challenges in thermal heavy oil recovery include how to monitor steam flood effectiveness and cap-rock integrity. Kuwait Oil Company acquired baseline 3D VSP surveys in January 2016 as geophysical surveillance projects for a steam flood pilot. This paper presents a technical approach of 3D VSP acquisition design, data processing, seismic inversion, quantitative interpretation and its application for the monitoring of steam movement.
Applying pressured steam to a reservoir can lead to damage of overlying cap-rock and could cause energy leakage through fractures. The technique of baseline 3D VSP and future time-lapsed 4D VSP are designed to image steam flood movement within the reservoirs. The possible applications of 3D/4D VSP technology include imaging the steam chamber size of a 30-day steam cycle, reservoir characterization and investigating integrity of the sealing cap shale.
Extensive planning and immaculate execution of the 3D VSP operations resulted in timely completion of survey acquisitions with high quality data. Because of the optimized acquisition parameters, the frequencies attained in these surveys were more than 30% higher than previously achieved in this same area. Extensive modeling enabled innovative customization of the acquisition design, optimized parallel processing, and interpretation techniques have allowed for a time effective acquisition-to-results turnaround that may affect the second cycle of the steam injection program. Resulting analysis on processed data clearly indicate the steam flow shape and direction. These significant results are providing important input for development decisions.
The reduction of the bin size from high fold and tight source / receiver distribution proven to be an effective and high quality method for imaging shallow geological target reservoirs. The resulting high frequencies obtained allowed for better vertical and spatial resolution, which enabled steam chamber size estimation and study of cap-rock integrity.
Past studies have shown that use of diluent injection with ESPs can be an efficient artificial lift method for heavy oil fields. It consists of injecting a light hydrocarbon liquid to reduce the oil density and viscosity. This paper describes an integrated modeling solution designed to maximize the reservoir oil production while minimizing the diluent requirement and keeping the crude oil quality within technical and marketing specifications. The field studied is an offshore heavy oil asset. It consists of two reservoirs with API gravities of 14 and 12, and oil viscosities at reservoir conditions of 70 cp and 500 cp. The field includes some 60 production wells.
Diluent can be injected (1) in each individual well at the ESP and (2) in the surface processing facility prior to the second stage separator. Operating constraints include (1) minimum wellhead pressure, (2) diluent availability, (3) final crude quality specifications, (4) maximum field oil and liquid production rate. The difficulty of the production optimization problem lies in the nonlinearity of the well production curves and viscosity model. In this paper, we develop a Mixed Integer Linear Programming (MILP) formulation by piecewise linearizing the nonlinear behaviors. For each well at each time step, we adjust the black-oil rates from a reservoir simulator to create piecewise linear well performance curves giving the reservoir oil production as a function of diluent injected at the ESP.
The proposed integrated solution is used for the entire production life of the field, which is still in the development phase. The solution is coupled with a reservoir simulator (1) to determine optimal diluent requirements over time, (2) forecast field production of reservoir oil, diluent, water and gas, and (3) foresee eventual bottlenecks in the infrastructure design (e.g. limiting constraints). The proposed solution can easily be used as a Real Time Production Optimization (RTPO) tool to find the optimal operating point based on the latest measurements (or real-time data). The optimal solution ensures the highest field reservoir oil production while meeting all constraints and keeping the diluent consumption at a minimum. The increase of the field oil production rate due to optimal diluent allocation ranges from 2 to 10 %. Cumulative reservoir oil production increases by approximately 3 million std m3.
The uniqueness of the solution comes from the integration of all operating constraints into a single mathematical formulation. The computational time (1s – 10s) of the proposed solution outperforms any classical nonlinear approach. This allows running many sensitivity analyses of the entire integrated asset model.
Adel, N. Abu (Australian College of Kuwait) | Abdullah, F. (Australian College of Kuwait) | Al-Kanderi, H. (Australian College of Kuwait) | Tesiari, E. (Australian College of Kuwait) | Ghafoori, S. (Australian College of Kuwait) | Alkazimi, M. A. (Kuwait Oil Company) | Al-Bazzaz, W. H. (Kuwait Institute For Scientific Research)
Extreme heavy oil <5 °API is considered a type of unconventional tight oil, which will require a challenging petroleum production system for future new-generation extreme heavy oil or bitumen carbonate reserves. This oil is abundant in great amounts around the globe, yet is extremely difficult to produce due to its solid-like physical state locked deep underground. The world strategy eventually will shift focus to this type of oil since conventional and other less-quantitative-difficult reservoirs are continuously depleting. The interest of this study is directed towards a specific type of unconventional oil, which is available in tight carbonate reservoirs. Extreme heavy oil <5 °API exists in large quantities in Kuwaiti fields. This study presents a novel heavy oil classification especially for <5 °API crude oil types as well as their potential recoveries. All recoveries considered for this study are bench-scale laboratory physical experiments with toluene, de-ionized water and water-aided surfactants augmented with applied field thermal 25 °C, 135 °C, 225 °C and 315 °C heat treatments.
The main objective for this research is to model five signature atoms available in almost all heavy crude oils: carbon, hydrogen, nitrogen, sulfur, and oxygen (CHNSO). These CHNSO fingerprints determine qualitatively and quantitatively the potential amount and quality of future extreme heavy crude oil recovery. An Artificial Intelligence (A.I.) neural network algorithm is developed for all possible conjecture atoms. A Multiple Layer Forward Feed (MLFF) learning system is designed, trained and applied for developing the A.I. neural network. Forty-one recovery models are manifested in this study, clustered in possible atom conjecture operational base-function domains, which are unary (one atom), binary (two atom), ternary (three atom), quaternary (four atom) and quinary (five atom) approach models.
The main technological motivation for CHNSO research is finding the optimized conventional EOR recovery efficiency factor that will extract <5 °API oil. The model predicts the recovery potential factor in a classic, optimum and conventional economic scenario, considering the unconventional environmental impact, crude oil subsurface-mobility issues and technology limitations used as current economic challenges.
The general summary of results suggest that CHNSO models are useful in better understanding and better predicting <5 °API oil recoveries. The three-atom nitrogen-sulfur-oxygen (NSO) ternary conjecture model has a significant impact regarding heavy crude oils, maximizing recovery in general, and extreme heavy oil potential recovery in particular, in regards to the difficult mobility of this type of crude oil.