Sour gas reservoirs with high content of sulfur are distributed widely around the world. Solid elemental sulfur which dissolves in the gas phase originally in the reservoir, may deposit when the thermodynamic conditions of the temperature, pressure or composition changes in the process of production. Deposition of solid elemental sulfur may block the pores in the formation and significantly affect the gas deliverability. In this paper, sulfur deposition mechanism is analyzed in the reservoirs. Based on the characteristics of sulfur deposition in the formation, a corrected function is introduced to modify the gas flow. Then, an evaluation method of the effect of sulfur deposition on gas deliverability is presented. For a practical sour gas reservoir, the gas deliverability considering sulfur deposition in formation is calculated and evaluated. The results show that the decrease degree of gas deliverability is different and it depends on the physical parameters in the formation on which the gas well is located.
Gas production and transportation pose challenges for operators. Unprocessed gas streams in production and flow lines containing brine and hydrogen sulfide are particularly corrosive and susceptible to forming hydrates and scale deposits. Methanol is often added to such streams for hydrate prevention; however, methanol increases the corrosion tendencies of pipes and equipment because it can deactivate some Corrosion Inhibitors (CI) and adds oxygen to the system. As a result, if hydrates are controlled with methanol, the system requires extra amounts of properly selected corrosion inhibitors to counteract the oxygen induced accelerated corrosion.
Corrosion rates of tubular steel exposed to sweet and sour brines were investigated. The sweet conditions contained carbon dioxide saturated brine, methanol, corrosion and gas hydrate inhibitors. Hydrogen sulfide was added to the system to create a sour environment. Methanol and hydrogen sulfide present in wet gas streams create an environment difficult for corrosion control; they accelerate corrosion rates to the point of rendering some commercial corrosion inhibitors unsuitable for corrosion protection. It was discovered that some gas hydrate inhibitors offer both, hydrates and corrosion protection. In addition it was found that the corrosion inhibiting properties of these gas hydrate inhibitors were enhanced in the presence of hydrogen sulfide.
The dual action of the Low Dosage Hydrate Inhibitor (LDHI) described here can limit or even eliminate Corrosion Inhibitors in highly corrosive methanol containing sour gas/water streams; thus, LDHI application improves production and transportation economy by replacing high volumes of methanol with less costly volumes of LDHI and providing additional operational savings on CI.
Gas hydrates form when water molecules crystallize around guest molecules. The water/guest crystallization process has been recognized since its discovery by Sir Humphrey Davy in 1810 it is well characterized and occurs with sufficient combination of pressure and temperature. Light hydrocarbons, methane-to-heptanes, nitrogen, carbon dioxide and hydrogen sulfide are the guest molecules of interest to the natural gas industry. Depending on the pressure and gas composition, gas hydrates may build up at any place where water coexists with natural gas at temperatures as high as 30°C (~85ºF).
Formation of undesired gas hydrates can be eliminated or hindered by several methods. The thermodynamic prevention methods control or eliminate elements necessary for hydrate formation: the presence of hydrate forming gas, the presence of water, high pressure and low temperature. The elimination of any one of these four elements from the system would preclude the formation of hydrates. Heating and insulating transmission lines is a common mechanical solution to the hydrate problem often encountered in long subsea pipelines. Gas dehydration is another method of removing a hydrate component. However, in a practical oil and gas operation, water can be economically removed to a certain minimum vapor pressure only and residual water vapors are always present in a dry gas. Hydrate plugs in "dry" gas lines have been reported in the past.
Tubular failures due to corrosion and pipelines plugging with solid hydrates are major concerns for gas production and transport operators. Hydrate plugs can form in a short time, often within a few hours at hydrate formation pressure and temperature (p/T) conditions. Corrosion is a significantly slower process taking months or years to manifest itself with hardware failing. Nevertheless, both processes can result in catastrophic consequences if left unchecked.
Recent advances in guar and cross-linker technologies have resulted in the development of high viscosity cross-linked borate fracturing fluids without increasing polymer loadings. These Low Polymer borate fracturing fluids (LP) are successfully being utilized in various formations previously believed to be too hot and or too deep for low polymer fracturing fluids.
Historically, polymer loadings of 3.6 - 4.2 kg/m³ (30-35 lb/1000gal) were commonly pumped in the Western Canadian Sedimentary Basin (WCSB) for formations deeper than 2500 meters and bottom hole temperatures greater than 80°C. These same formations are now fracture stimulated using the Low Polymer fluids with loadings as low as 1.8 kg/m³ (15 lb/1000gal) with exceptional results.
This paper demonstrates that Low Polymer fracture fluids can be used in place of higher polymer fluids with minimal changes to the overall design of the fracture treatment. The new fluid can be pumped on-the-fly at conventional pump rates and proppant concentrations due to the fluid's improved shear and temperature stability.
The advantages of using a reduced polymer fracturing fluid include increased production, lower treatment costs, and lower friction pressures.
This paper illustrates these advantages as it compares the Low Polymer fracture fluid with High Polymer fracture fluids in over 200 wells in the WCSB. The formations where LP fluids were utilized have depths of up to 3250 meters and reservoir temperatures reaching over 100°C.
Advances in technology, strong energy prices and declining reserves in conventional gas reservoirs are encouraging oil and gas companies to consider the feasibility of exploiting large reserves trapped in tight (low permeability) gas reservoirs.
Conventional well tests conducted on these low permeability gas formations, generally result in poor estimates of key reservoir parameters such as: initial reservoir pressure, permeability, effective fracture length, fracture conductivity, and deliverability potential.
The objective of this paper is to review the different types of tests that are particularly applicable to tight gas formations, discuss why the traditional methods of testing and analysis rarely succeed, and identify appropriate test and analysis procedures for tight gas reservoirs.
We will consider short-term tests where the primary objective is to obtain the initial reservoir pressure, with a secondary objective of determining permeability and skin. Perforation Inflow Tests, Fracture-Calibration Tests, and Formation Flow Tests will be considered. The applicability of these tests will be shown using synthetic and actual field cases.
This paper will illustrate the collaborative approach taken by an integrated team (operator and service company) charged to demonstrate, within a one-year time period, measurable improvement in well productivity in the Saih Rawl field of Oman. Although the field has been producing for more than five years, the results shown are based on a one-year application of a systematic approach to field optimization. This process is the dynamic integration of historical data and new information, technologies, and engineering diagnostics to systematically identify, layer-by-layer, key parameters affecting productivity and to optimize performance based on "present-state?? analyses. In doing so, the program has produced some of the highest productivity wells in the field's history.
Oman has developed into a fast-paced fracturing arena, with challenges similar to those encountered in the tight gas fields of south Texas in the United States. Well productivity is highly dependent on hydraulic fracturing effectiveness and operating practices. Understanding the resultant hydraulic fracture effectiveness is increasingly complicated by the changing mechanical and reservoir properties related to depletion and intralayer communication (crossflow).
Gas is produced in the Saih Rawl field from two distinct main reservoirs: the Barik and Miqrat formations. The Barik formation, at depths from 4500 to 4900 m, is composed of stacked sandstone packages with varying shale content separated by relatively thin heteroliths (sandstone/shale mixtures) of 3 to 7 m thickness. These heteroliths are believed to provide pressure barriers to the various flow units observed in the Barik formation. The Barik formation produces gas of varying richness from most of its units, with a high condensate content produced from layers that are producing currently below dewpoint. On the other hand, the Miqrat formation, found at depths >5100 m, produces lean or dry gas. The combination of relatively low and heterogeneous permeability along with complex hydraulic fracture height growth makes it necessary to perform ad hoc, multistage hydraulic fracturing treatments and to produce these wells commingled to be commercially economic. A systematic approach, incorporating historical pressure trends by unit and theoretical assumptions, validated by indirect field evidence, to onsite decision-making has resulted in the placement of more effective fracture treatments in an operationally efficient manner. The results of these efforts yielded the highest producing well in the field's history in an area of known depletion; the highest-rate Miqrat production well, an overall improvement of zone productivity, and a better understanding of the factors impacting productivity, layer-by-layer, in the Barik and Miqrat formations.
Bulova, Marina Nikolaevna (Schlumberger R&D Inc.) | Cheremisin, Alexey Nikolaevich (Schlumberger R&D Inc.) | Nosova, Ksenia Evgenievna (Schlumberger R&D Inc.) | Lassek, John T. (Schlumberger) | Willberg, Dean
To achieve maximum production, tight-gas formations require long fractures with contained height growth. This can be achieved by using low viscosity fracturing fluids. Decrease in fluid viscosity typically leads to an increase of proppant settling rate which results in non-uniform proppant placement and reduced effective fracture conductivity. Low-density proppants can offset this effect in low-viscosity fluid, but due to their low strength can be applied only at low closure stresses and relatively low temperatures.
A new fluid system was developed especially for fracturing low-permeability formations (less than 0.01 mD). This system allows for high-strength high-density ceramic proppant to be used with reduced polymer loading and significantly decreased proppant settling rates. All these benefits are the result of adding fibers into a fluid system which create a network, helping to suspend proppant during its transport and placement into a fracture.
Laboratory studies were performed to determine the fiber's influence on long-term proppant-pack permeabilities. Retained conductivities of ceramic and sand proppant packs over the 175-250 ºF temperature range were measured under various loadings and closure stress ranges. Testing has shown permeability values of the fiber-laden systems are comparable with the values for fiber-free proppant packs. A parallel study was performed on evaluating proppant settling rates in fiber-laden fluids in static conditions. Fiber in a fracturing fluid system reduces the rate of proppant settling by greater than three-fold.
Special attention is paid to a proper proppant selection for hydraulic fracturing. Improper proppant selection can cause significant damage of proppant pack conductivity and minimize benefits of the fluid system.
The results prove that the innovative fiber fluid ensures uniform proppant placement within a long fracture because of fiber presence, provides conductivity comparable to pure proppant pack values, and do not have any limitations at high closure stresses.
Some of the significant strides made in coal stimulation during the last 25 years can be attributed to the development of new-generation fluid systems (i.e., low gel loading fluids with efficient low-temperature breaker systems that cause less polymer damage in coals). All these new developments were implemented to (a) minimize damage in coals, and (b) maximize production. Water fracture treatments in coals completely eliminated polymer damage but did not always maximize production. The use of new-generation crosslinked fluids did provide better half-lengths and conductivities but still left residual damage in coals. Based on production, it was confirmed that the benefits obtained with this fluid system outweighed the damage created. To further reduce the damage in coals and obtain better regained fracture permeability, implementing hybrid fracture treatments in coals was considered in this San Juan basin project. The term "hybrid" in this case refers to a water pad followed by crosslinked fluid sand stages. Potential benefits of this technique in coals include: (a) minimizing damage caused by gel, (b) maximizing regained permeability, (c) containing height growth, and d) lowering cost.
There are two parts to this work. The first part presented in this paper contains the design, implementation, and encouraging initial results obtained from the seven wells in this project, which is in an underpressured area. This is the first project in which hybrid-type treatments have been applied in a low-pressured formation. This paper will discuss the lessons learned from such an application in coals. When sufficient production data becomes available, the second part of this work will quantify the results via reservoir simulation. The second part will also include quantified results from another current hybrid fracture-stimulation project where the coals are slightly overpressured.
The demand for natural gas has pushed energy industries toward the discovery of remote offshore reservoirs. Consequently, new technologies have to be developed to efficiently produce and transport natural gas to consumption centers. Common design challenges in all gas processing methods for offshore applications are the compactness and reliability of process equipment. Water vapour is the most common impurity in natural gas mixtures. At very high gas pressures within the transportation systems hydrate can easily form even at relatively high temperatures. Gas dehydration or hydrate inhibition systems for offshore gas production/processing facilities should meet these requirements. It should also be noted that at certain pressure and composition conditions, the presence of heavy hydrocarbons (C2+) in natural gas increases pipeline flow capacity and improves compression efficiencies. Therefore, the development of a compact high pressure system capable of selectively removing water from high pressure natural gas streams without affecting the hydrocarbon content will be needed for especial applications and therefore it will be addressed in this paper. Most hydrate inhibition/water removal systems can only work below certain pressure conditions, are relatively large, and not selective towards water. Therefore, some hydrocarbon condensate is also removed during water dew pointing. The developed technique proposed in this study can be customized for the emerging marine transportation of gas in CNG form where the removal of heavier hydrocarbons might not be necessary and will be equally suitable for any other offshore/onshore natural gas production and processing including subsea production of oil and gas. This paper concentrates on the development of simulation techniques needed to accurately estimate dehydration efficiency to control hydrate in a supercritical flow using supersonic nozzles.
A simulation model linked to a thermodynamic property generator is needed to predict the water removal efficiency under various flow conditions. The computer simulation results for water removal from a typical offshore natural gas stream under various conditions will be presented and compared with conventional techniques. Intensive water dew points down to about -50 to - 60 ºC can be achieved without any cryogenic cooling or use of solid adsorption techniques.
Paktinat, Javad (Universal Well Services Inc.) | Pinkhouse, Joseph Allen (Universal Well Services Inc.) | Williams, Curtis (Universal Well Services Inc.) | Clark, Gary Allen (Phillips Production) | Penny, Glenn S. (CESI Chemical)
The primary purpose of surfactants used in stimulating sandstone reservoirs is to reduce surface tension, contact angle and leakoff control. However, many of these chemicals adsorb rapidly within the first few inches of the sandstone formations, reducing their effectiveness in deeper penetration. This phenomenon causes surfactants to adsorb or plate-out reducing their effectiveness in post fracturing fluid recovery.
This study describes experimental and field case studies of various surfactants used in the oilfield. Several different surfactants including a nonionic ethoxylated linear alcohol, nonyl phenol ethoxylate, an amphoteric, a cationic and a microemulsion system were investigated to determine their adsorption properties when injected into a laboratory sand packed column. A laboratory simulated comparison study of commonly used surfactants and microemulsion was used to identify their leakoff and water recovery properties from gas wells.
Field data collected from Bradford, Balltown and Speechley sandstone formations confirmed experimental sand packed column and core flow investigations. Reservoirs treated with microemulsion fluids demonstrate exceptional water recoveries when compared with conventional surfactant treatments. Wellhead pressures, flowing pressures and production data were collected and evaluated using a production simulator to show effective fracture lengths, damage surrounding the fractures and drainage areas with various fluid systems. These investigations and presented case studies can be used to minimize formation damage.
Gas recycling experiments were conducted on a gas condensate sample in a fractured model. Experimental Model was then numerically simulated with compositional simulator. The objectives were to investigate effects of gas recycling on condensate recovery from a naturally fractured reservoir under complete pressure maintenance process.
In laboratory scale we could accurately analyse behavior of in-place and injected gas in fracture and matrix blocks and understand how the production mechanisms affect ultimate recovery in this reservoir model. In reservoir scale, due to high heterogeneity and lack of required data such an accurate investigation is impossible.
In the simulated model after history matching of cumulative gas and condensate production and composition variation history of produced gas, some sensitivity analysis were performed. Simulation results show that gas recycling increases liquid recovery more than 2.5 times for the reservoir if the fracture model behaves as dual permeability fractured reservoir. If model behavior supposed to be dual porosity, condensate recovery decreases dramatically due to early break through of injected gas via fractures. Cyclic injection-production and decreasing the production rate are the factors directing the process to higher ultimate recoveries. Nitrogen injection effect has also been established showing less recovery than dry gas injection case.
Finally, lacks of data for a complete compositional simulation of such models are mentioned. If the data be prepared prior to performing the experiment, results could be up-scaled to the reservoir with higher degree of assurance.