Guest editorial - No abstract available.
Gas transient flow in a gas pipeline and gas tank is critical in flow assurance. Not only does leak detection require a delicate model to simulate the complicated yet dramatically changed phenomena, but gas pipeline and gas tank design in metering, gathering, and transportation systems demands an accurate analysis of gas-transient flow, through which efficient, cost-effective operation can be achieved.
Traditionally, there are two types of approaches used to investigate gas-transient flow: one involves treating gas as ideal gas so that the ideal gas law can be applied and the other considers gas as real gas, allowing the gas compressibility factor to come into play. Needless to say, the former method can result in an analytical solution to gas transient flow with a deviation from the real-gas performance, which is very crucial in daily operation. The latter approach requires a numerical method to solve the governing equation, leading to instability issues with a more-accurate result. Our literature review indicated that no study considering the effect of changing gas viscosity on the transient flow was available; therefore, this effect was included in our study.
Our investigation showed that viscosity does have a significant influence on gas-transient flow in pipe- and tank-leakage evaluation. In this study, a comprehensive evaluation of all variables was performed to determine the most-important factors in the gas-transient flow. Several case studies were used to illustrate the significance of this study. Engineers can perform a more-reliable evaluation of gas transient flow by following the method we used in our study.
Global demand for natural gas continues to grow because it is favored as an environmentally attractive fuel relative to other hydrocarbon fuels. By 2035, the US Energy Information Administration (EIA) projects global natural gas consumption will have increased from approximately 113.1 Tcf in 2010 to 168.7 Tcf (Fig. 1).
Al-Ruheili, Sharifa Moh'd (Petroleum Development Oman) | Angelatos, Matthew (Petroleum Development Oman) | Ramakrishnan Nair, Sujith Kumar (Petroleum Development Oman) | Peringod, Chandran (Petroleum Development Oman) | Sonti, Kartik (Shell India Markets Private Ltd) | Karacali, Ozgur (Schlumberger Oman & Co LLC)
In Auto gas-lifted wells, gas from either a gas zone or gas cap is used to lift oil in a commingled way. Balancing gas zone energy depletion to the benefit of oil production requires an accurate understanding of zonal contribution and an ability to adjust and control inflow from both zones.
A project was undertaken for accurate zonal allocation and optimization of lift gas rates by designing an appropriate zonal contribution measurement procedure for five Auto gas-lifted wells on two fields. This approach utilized both production logging and production testing to obtain both zonal down hole and commingled surface flow measurements. As a result of the exercise, lift gas flow into the tubing was optimized, thus maximizing the oil production rate while conserving reservoir energy through efficient gas usage.
Measurement of zonal contributions in multi-zone intelligent well completions are often challenging due to the complex nature of fluid flow under varying dynamic conditions of multiple reservoirs. This paper will explain the zonal contribution measurement program design, implementation, interpretation of data and lessons learnt from the project.
The B Field is a part of the North Asset of Petroleum Development Oman. This field was discovered in 1973 and put on-stream in 1986. The three reservoirs, Upper G1, Middle G2 (both low net to gross fluvial sandstones) and Lower G3 (thin, high net to gross shore face sheet sands) have very light oil (42 API, 0.32-38 cP) contained in 13-57 m thick oil rims at depths of about 2500-2700m ss.
A Field Development Planning (FDP) study to investigate further development strategy in the B field was completed in 2004. The plan included drilling 32 production wells and 4 dedicated gas injection wells, a water injection pilot and contingent follow-up water injection phases. Ultimately, gas-cap blow-down was proposed for the 2015 timeframe.
Alipour Kallehbasti, Mehdi (National Iranian Oil Company) | Rostami Paroodbari, Javad (National Iranian Oil Company) | Alizadeh, Nasser (Schlumberger) | Rostami Ravari, Reza (Statoil ASA) | Amani, Mahmood
Gas injection is a common practice in many carbonate oil fields; however, there is a lot of debate around the viability of economical enhanced oil recovery by miscible gas injection. For a correct simulation of miscible gas injection and monitoring the progress of the miscible front in the reservoir, a compositional reservoir simulation is needed. Fluid characterization is one of the most important parts of this simulation.
In this paper, fluid characterization for such a mechanism is discussed and a systematic approach is presented which could be used in any other similar study. The dynamic reservoir simulation is also brought at the end for comparison. The carbonate reservoir of the field of interest, contains 900 million barrels of under-saturated, 34 API degrees oil, with initial reservoir pressure of 8200 psi. After building a PVT model and adjusting the Equation of State (EOS), the Minimum Miscibility Pressure (MMP) of four different injection gases (N2, CO2, associated gas and sales gas) were calculated with different methods. Swelling test and slim tube test were also conducted which were used to cross check the EOS tuning. Although, MMPs in all cases were much lower than initial reservoir pressure, their effects on recovery factor were different. A compositional reservoir model was built based on the tuned EOS and the effects of all injection gases in different scenarios were examined. The procedures as well as the main results are explained in this paper.
To satisfy the growing global gas demand more reservoirs with sour contaminants (up to 40% of H2S and significant CO2) will be developed. Worldwide more than 1600 TCF of Sour Gas is anticipated. Shell has more than 60 years of experience in sour gas processing, ranging from the first facilities installed in Jumping Pound, Canada, to recent projects under development in Kazakhstan and Oman. This paper will describe a number of challenges and opportunities associated with development of "sour?? projects.
The fact that H2S is lethal at low concentrations and highly corrosive in the presence of CO2 and/or (salty) water indicates that safety is a main driver in these projects. It is of crucial importance that the H2S is contained and that plant integrity is assured through tightly controlled maintenance programs.
Product specifications for produced gas and hydrocarbon liquids are ever tightening and legislation on emissions are becoming more stringent. Deep removal of H2S and other sulphur components like mercaptans and carbonyl sulphide is required. This increases the complexity and therefore cost of the sour gas processing facilities, which must compete with production from sweet gas in the region/country or alternatives such as LNG import. Technology innovation as well as smart integration of technologies are essential for the cost effective development of sour gas assets ensuring all specifications and emission requirements are met. Several examples of these technology innovations will be presented in this paper.
Gas Processing Facility (GPF) project achieved Zero flaring.
1.7million standard cubic feet per day (41.65 tons) gas recovered thru Vapor Recovery System and protect the environment by reducing;
CO2 : 3,924 tons/yr
CO: 123.6 tons/yr
NOx: 21.6 tons/yrs
Ø Total gas recovered: 612 million standard cubic feet per year
Ø Revenue saving: 835,380 US$ /year
Vapor Recovery Unit (VRU):
Under this unit, gases from the Tertiary Ethyl Glycol (TEG)Dehydration package and vents from compressors dry gas seals are recovered/ captured and compressed in the VRU and then sent to the suction for the main gas compressor for reuse instead of going to flare
Gas Processing Project (GPF) at Zakum complex is a new gas treatment platform that will augment the existing gas processing capacity of the Zakum West Super Complex. It will increase the associated gas production from Zakum oilfield. The beauty of this project is that ADMA has employed the Zero flaring policy. There will be no flaring at all at this platform. This is one of the unique project of its nature in the ADNOC group of companies, even in Emirates and could be in the whole middle east where is there would be NO flaring. We have designed flare as well in this project but that would be used only for emergencies.
GPF is a stand alone platform with independent utilities and support facilities. The GPF platform is 67.5 meter in length and 43 meters in width. GPF is located at Zakum oilfield, offshore facility about 65 kilometer Northwest of Abu Dhabi. This platform has three main decks, cellar, mezzanine and main. The flare structure consists of a 120 meter long flare bridge with a 80m above sea level angled boom. The distance from the flare tip to the GPF platform is150 m.
There will not be any flaring during normal operation of the GPF, as Zero flaring technology is installed. Hydrocarbon from the GPF platform will be recovered using a Vapour Recovery Unit (VRU) facility. Flaring will only be undertaken during emergency conditions.
Natural gas exploration and production from shale gas formations have gained great momentum throughout the world in the last decade. Producing natural gas from shale is challenging because of the high uncertainty in well productivity. It is
imperative to investigate and understand the gas flow mechanism in the shale gas formations. This paper investigates the shale gas production mechanism based on field case studies.
Guo et al.'s analytical well productivity model was employed in this work for analyzing gas productivity of a shale gas well in the Fayetteville Shale basin. Model analyses indicate that shale heterogeneity (natural fractures/custers and organics spots)
is a favorable characteristics of shale gas reservoirs because they contribute to the initial and long-term well productivity. Shale gas reservoirs without natural fractures/clusters will not produce natural gas at commercial rates even a few hydraulic
fractures are created. The intensity of natural fractures/clusters is a key factor affecting the potential of shale gas wells. Hydraulic fractures are useful for intersecting natural fractures/clusters to make well more productive, but it is not necessary
to create high-conductivity fractures for this purpose. Shale gas wells should be placed in the areas where high-natural fracture intensity and solid organic material contents are present.
A basin centered gas accumulation (BCGA) is a "continuous petroleum accumulation?? characterized by low permeability, the absence of downdip water, the absence of obvious traps and seals, the presence of pervasive gas or oil saturation over very large areas, abnormal pressures (either high or low), and the relative proximity to source rocks. The question is if it is reasonable to think that gas can be trapped over millions of years by an updip water block.
A reservoir simulation model has been created in order to answer this question. The water seal is shown to be the result of very low permeability and high capillary pressures, properties that are generally found in tight gas formations. The model is defined by a geometry that mimics the geologic interpretation of the Nikanassin BCGA in the Western Canada Sedimentary Basin (WCSB) and rock properties that provide a good representation of the real behavior of the reservoir in the Deep Basin. Different models were created trying to understand sensitivities to permeability and capillary pressure in the distribution of downdip gas and updip water over thousands of years. The results obtained appear consistent and reliable when compared with factual information from the Deep Basin.
The conclusion is reached that updip water blocks provide good seals in the Deep Basin. The simulation also confirms that special completion and stimulation practices are required in order to produce gas at economic rates from tight gas reservoirs.
The qualifier "unconventional?? for tight gas reservoirs is certainly valid. The lack of water leg, the seal provided by a "water block?? updip the gas reservoir, the porosity associates with slots and dissolution secondary pores, the abnormal pressure (high or low with respect to a normally pressured reservoir) and the very large continuous areas where they are found make them certainly "unconventional??. We present the terminology associated with these types of reservoirs next.
Basin Centered Gas Continuous Accumulation
Basin centered gas accumulations, tight gas formations; coalbed methane, oil and gas shales, and gas hydrates are generally categorized as "continuous petroleum accumulations??. Those continuous accumulations have two key geologic features in common: first, they consist of very large areas with pervasive oil or gas saturation, and second they do not depend upon the buoyancy of oil or gas in water for their existence. Petroleum as defined by the United States Geological Survey is the sum of oil, natural gas and natural gas liquids.
In addition to the key features mentioned above, there are other important characteristics of continuous accumulations including the lack of down dip water, absence of obvious trap and seal, large areal extent, low matrix permeability, abnormal pressure (either high or low), and close proximity to source rocks.