Effect of availability on multi-period planning of subsea oil and gas production systems

Natural gas and petroleum are non-renewable and scarce energy sources. Although, it is well known that hydrocarbon reserves are depleting through the years, oil and gas remain the principal source of energy upon which our society is strongly dependent. Hence, optimization and accurate planning of hydrocarbon production are the main keys to making it safer, more efficient, and cheaper. One of the tools commonly used to evaluate the optimization of oil/gas production system is the process simulation modeling. A hydrocarbon production system typically consists of at least one underground reservoir where several wells have been drilled into the hydrocarbon-bearing rock to form a fixed topology network. Wells are interconnected with manifolds to transport the gas or oil to a storage or sale location. The process simulation consists of calculating the total hydrocarbon production for the given production system. The pressure in the wellbore is the main variable in determining the hydrocarbon production process. When oil/gas is produced, the pressure decreases until production cannot be sustained. If the well is shut down, the pressure at the wellbore increases because of the natural gas flow coming from the reservoir. In addition, artificial lift techniques, such as water injection, gas lift and pump systems can be incorporated into the simulation program. The oil/gas production has been also modeled as a multi-period optimization case to incorporate the possibility of different demands, cost and overall time behavior. The current field optimization approaches take in account the availability in a general way, adding to the planning a lot of uncertainty. The proposed study includes a suitable analysis of the likelihood of equipment failure, which will predict the availability of the equipment in a certain period of time to perform a more accurate planning. In this work, we have integrated the availability analysis to the model described above. The availability of a system is analyzed by Monte Carlo simulation, which involves the modeling of the probabilities of failure, the type of failure, the time to repair associated with each failure, and time of occurrence for a field system. The availability model performed reduces significantly the uncertainties on a multi-period planning production of either oil or gas, predicting the probability of failure and the downtime related to the hydrocarbon production through its lifetime. In this study, the unavailability of the equipment was quantified, reporting a subsea equipment downtime of approximately 7%. As a result, new production planning is accomplished in the effective work period, which will be beneficial in financial risk decisions such as a government’s deliverability contracts

Optimization of production allocation under price uncertainty : relating price model assumptions to decisions

textAllocating production volumes across a portfolio of producing assets is a complex optimization problem. Each producing asset possesses different technical attributes (e.g. crude type), facility constraints, and costs. In addition, there are corporate objectives and constraints (e.g. contract delivery requirements). While complex, such a problem can be specified and solved using conventional deterministic optimization methods. However, there is often uncertainty in many of the inputs, and in these cases the appropriate approach is neither obvious nor straightforward. One of the major uncertainties in the oil and gas industry is the commodity price assumption(s). This paper investigates this problem in three major sections: (1) We specify an integrated stochastic optimization model that solves for the optimal production allocation for a portfolio of producing assets when there is uncertainty in commodity prices, (2) We then compare the solutions that result when different price models are used, and (3) We perform a value of information analysis to estimate the value of more accurate price models. The results show that the optimum production allocation is a function of the price model assumptions. However, the differences between models are minor, and thus the value of choosing the “correct” price model, or similarly of estimating a more accurate model, is small. This work falls in the emerging research area of decision-oriented assessments of information value.Petroleum and Geosystems Engineerin

Subsea Production System (SPS) Control Modelling

The motivations of this project work are to develop a simulation model for a direct hydraulic control system, find the effect of changing key parameters to the system’s response time, and also to demonstrate Emergency Shut Down (ESD) feature which is a requirement for the subsea production control systems (SPCS). The methodology of this project involves selecting a control system to be studied which is a direct hydraulic control system, gathering technical details and data regarding the control system and components that constitute the control system, and translating the technical details and concepts into acceptable simulation forms in the simulation’s software. This project used SimulationX to simulate the developed model. The developed model consist of a hydraulic power unit, a topside control panel, hydraulic lines, a subsea control module and two actuator valves. The Cadlao oil field has been selected as the case study and simulation models were built according to the Cadlao field’s SPCS. The simulated model is validated by comparing the Cadlao’s performance curves and the acquired results. The simulation is done by varying 3 parameters which are umbilical length, umbilical diameter, and actuator size. Each parameter is tested to study its influences on the signal time and shift time. To find the effect of umbilical length on the signal time, umbilical lengths of 6000 ft, 12000 ft, and 18000 ft have been used. Time taken are 47 s, 110 s, and 195 s respectively. For the simulation using different umbilical diameters, 0.15 inch, 0.35 inch and 0.50 inch have been used. Time taken to fully pressurize the umbilical are 111 s, 39 s and 48 s respectively. For the second part, to find the effect of varying parameters on shift time, three parameters are changed (umbilical length, umbilical diameter and actuator diameter). 6000 ft, 12000 ft and 18000 ft umbilical lengths have been used and the recorded shift times are 13 s, 21 s and 31 s respectively. For the simulation using different umbilical diameters, 0.15 in, 0.35 in and 0.50 in have been used and the recorded shift times are 113 s, 19 s and 13 s respectively. Lastly, sensitivity analysis is done using three different piston diameters. Diameters of 6 in, 9 in and 12 in have been used and the recorded shift times are 28 s, 36 s and 56 s respectively. Lastly, emergency shut-down simulated showed that the actuator is able to return to fail safe condition in 33 s

Reversing Wetland Death From 35,000 Cuts: Opportunities To Restore Louisiana\u27S Dredged Canals

We determined the number of permits for oil and gas activities in 14 coastal Louisiana parishes from 1900 to 2017, compared them to land loss on this coast, and estimated their restoration potential. A total of 76,247 oil and gas recovery wells were permitted, of which 35,163 (46%) were on land (as of 2010) and 27,483 of which are officially abandoned. There is a direct spatial and temporal relationship between the number of these permits and land loss, attributable to the above and belowground changes in hydrology resulting from the dredged material levees placed parallel to the canal (spoil banks). These hydrologic modifications cause various direct and indirect compromises to plants and soils resulting in wetland collapse. Although oil and gas recovery beneath southern Louisiana wetlands has dramatically declined since its peak in the early 1960s, it has left behind spoil banks with a total length sufficient to cross coastal Louisiana 79 times from east to west. Dragging down the remaining material in the spoil bank back into the canal is a successful restoration technique that is rarely applied in Louisiana, but could be a dramatically cost-effective and proven long-term strategy if political will prevails. The absence of a State or Federal backfilling program is a huge missed opportunity to: 1) conduct cost-effective restoration at a relatively low cost, and, 2) conduct systematic restoration monitoring and hypothesis testing that advances knowledge and improves the efficacy of future attempts. The price of backfilling all canals is about $335 million dollars, or 0.67% of the State\u27s Master Plan for restoration and a pittance of the economic value gained from extracting the oil and gas beneath over the last 100 years

Subsea fluid sampling to maximise production asset in offshore field development

The acquisition of representative subsea fluid sampling from offshore field development asset is crucial for the correct evaluation of oil reserves and for the design of subsea production facilities. Due to rising operational expenditures, operators and manufacturers have been working hard to provide systems to enable cost effective subsea fluid sampling solutions. To achieve this, any system has to collect sufficient sample volumes to ensure statistically valid characterisation of the sampled fluids. In executing the research project, various subsea sampling methods used in the offshore industry were examined and ranked using multi criteria decision making; a solution using a remote operated vehicle was selected as the preferred method, to compliment the subsea multiphase flowmeter capability, used to provide well diagnostics to measure individual phases – oil, gas, and water. A mechanistic (compositional fluid tracking) model is employed, using the fluid properties that are equivalent to the production flow stream being measured, to predict reliable reservoir fluid characteristics on the subsea production system. This is applicable even under conditions where significant variations in the reservoir fluid composition occur in transient production operations. The model also adds value in the decision to employ subsea processing in managing water breakthrough as the field matures. This can be achieved through efficient processing of the fluid with separation and boosting delivered to the topside facilities or for water re-injection to the reservoir. The combination of multiphase flowmeter, remote operated vehicle deployed fluid sampling and the mechanistic model provides a balanced approach to reservoir performance monitoring. Therefore, regular and systematic field tailored application of subsea fluid sampling should provide detailed understanding on formation fluid, a basis for accurate prediction of reservoir fluid characteristic, to maximize well production in offshore field development

Numerical modeling of nitrogen injection into gas condensate reservoir

Gas-condensate reservoirs differ from dry-gas reservoirs. Gas condensate production is predominantly gas from which a quantity of liquid is condensed; the amount condensed being based on the gas-oil-ratio, GOR, in surface separators. Condensate dropout occurs in the reservoir as the pressure falls below dew-point, as a result of which, the liquid production decreases significantly and the condensate formed in the reservoir is also unrecoverable. Injection and cycling of dry natural gas has been used to enhance the condensate production from these reservoirs. However natural gas has become more valuable and alternative gases must be investigated. One of such gas is nitrogen which is inert and can be generated inexpensively at the well site.;The purpose of this research study was to develop a gas condensate reservoir model to determine the effects that nitrogen injection has on the condensate recovery. In order to build a realistic reservoir model, data from a deep high pressure gas condensate field was used. The results of this study indicated that for original well pattern, nitrogen injection did not show an overall benefit to condensate recovery. However alternative development plan for the reservoir showed increased condensate producibility and thus the viability of nitrogen injection

Hydraulic fracturing: a look at efficiency in the Haynesville Shale and the environmental effects of fracking

Hydraulic fracturing has become a hot topic in America’s growing, domestic, oil and natural industry. This new technology has provided an economic way to extract resources from tight oil and gas shale formations found deep underground, but this new way of drilling does not come without environmental and human health effects. Among these health effects are water usage, water quality, and air quality. In this paper, data from Frac Focus.org was used to get the average amount of water used per well, and the average amount of chemicals, and what those chemicals are, for each well in the Haynesville Shale. An extensive literature review was used to get average air emission data from drilling and hydraulic fracturing. Data from the Louisiana Department of Natural Resources’ SONRIS was used to find average drilling statistics associated with Haynesville Shale wells and used to determine drilling and hydraulic fracturing efficiency. These parameters were then used estimate air emissions, water usage, and chemical use in the Haynesville Shale. It was found that on average an unconventional well in the Haynesville Shale used 6.5 million gallons of water. The top three chemicals used in fracking fluid were found to be: Hydrochloric Acid, Phenol, and Quaternary Ammonia Salts, used at an average concentration of 0.21%, 0.086%, and 0.02%, respectively. Air emissions from unconventional drilling processes were estimated for NOx, CO, VOC, PM, SOx, CO2, and CH4. Overall, the drilling process in the shale was found to emit the most amount of emissions, except for CH4 where fracturing emitted the most. Lastly, using the drilling parameters and water use calculations, evidence was shown that learning by doing was taking play in the Haynesville Shale and that efficiency, in some aspects of the well development activities, was being achieved

Better understanding of production decline in shale gas wells

Thesis (M.S.) University of Alaska Fairbanks, 2014.Production data from the Eagle Ford shale (an analog to the Alaska Shublik shale) was collected from two neighboring counties and analyzed to correlate well performance with completion parameters including length of horizontal wellbore and number of hydraulic fracturing stages. Thirty-eight dry gas wells with production history range of 18-43 months were analyzed using 6 different decline curve analysis (DCA) models including Arps' exponential, harmonic and hyperbolic, power law exponential (PLE), logistic growth analysis (LGA) and Duong's models. In the matching process, 2/3 of history was used to tune the DCA models and their forecasts were compared to the remaining 1/3 of real history. The matching results were analyzed based on production history length and flow regime to have better understanding of limitations and capabilities of each DCA model. Reservoir simulation models, constructed using range of realistic data and actual completion practices of 4 select wells, were employed to assess reasonable values of remaining reserve and remaining well life that were used as benchmarks for comparison with DCA results. The results showed that there was no strong correlation between well performance (average first year production rate) and the horizontal leg or the number of fracturing stages. This was an indication of extremely heterogeneous medium. In most cases, the accuracy of the DCA models increased when longer production history was used to tune the model parameters. LGA seems to be the most accurate DCA model since it gave the highest matching accuracy 71% of the total wells when using longest history length of 31 months. As the flow regime is concerned, LGA model also performed very well matched in 57% of the wells exhibiting only transient flow and 63% for the wells showing transient flow during early production time followed by boundary-dominated flow during late production. Moreover, the remaining reserve and well life of the select wells predicted by LGA fell into reasonably close range of the estimates from the reservoir simulations