Shubham, Agrawal (Texas A&M University at Qatar) | Martavaltzi, Christina (Texas A&M University at Qatar) | Dakik, Ahmad Rafic (Texas A&M University at Qatar) | Gupta, Anuj (Texas A&M University at Qatar)
It is well known that the majority of carbonate reservoirs are neutral to oil-wet. This leads to much lower oil recovery during waterflooding since there is no spontaneous imbibition of water in heterogeneous reservoir displacement. It has been verified by a number of researchers that Adjustment of ion concentration in brine solutions, or adding surfactant solutions can enhance the oil recovery by altering the wettability. In the published literature, contact angle studies usually refer to measurement on calcite crystals and there are no results for the contact angle of carbonate porous media representative of reservoir rocks. Moreover, there are few studies on the effect of non-ionic surfactants, compared to those for ionic surfactants. Understanding the effect of various ions and their concentration in the injection brine on the wettability of the Limestone outcrop core samples is the first step for tailoring of the optimum injection brine. This will be followed by a study of the effect of surfactant on the wettability of calcite crystal samples. The evaluation of the results may provide guidelines for the design of injection brines for efficient enhanced oil recovery from carbonate reservoirs.
In this work, a procedure is established for the measurement of the contact angle on limestone outcrop core samples. Results showed that, at atmospheric conditions, low salinity CaCl2 solution induced the most significant improvement on the wettability of the outcrop sample. Moreover, among all the non-ionic surfactants studied, only the presence of the two first members of the 15S analogous series might lead to a slight decrease of the contact angle.
Minagawa, Hideki (National Institute of Advanced Industrial Science and Technology) | Egawa, Kosuke (National Institute of Advanced Industrial Science and Technology) | Sakamoto, Yasuhide (National Institute of Advanced Industrial Science and Technology) | Komai, Takeshi (National Institute of Advanced Industrial Science and Technology) | Tenma, Norio (National Institute of Advanced Industrial Science and Technology) | Narita, Hideo (National Institute of Advanced Industrial Science and Technology)
A proton nuclear magnetic resonance (NMR) system combined with a permeability measurement system has been used to clarify the relation between permeability and a methane-hydrate saturation in methane-hydrate-bearing sediment with regard to effective pore-size distribution. Pore-size distributions of sediments have been calculated using the relaxation time distribution of NMR-T2. Two different laboratory methods for growing gas hydrate in sediment cores have been used to determine the relationship between hydrate saturation and permeability: a conventional approach called the connate water method, and a dissolved-gas method. The 2 methods produced different permeability and pore-size distribution of sediment.
Methane hydrates (MH) in sediment are expected to be developed as a resource for natural gas and have been studied as a possible future energy resource. In-situ dissociation of the naturalgas hydrate is necessary for commercial recovery of natural gas from natural-gas-hydrate-bearing sediment (i.e., mainly MHbearing sediment) (Makogon, 1981, 1988). Various methods of producing methane gas from MH have been proposed for exploiting MH (e.g., depressurization (Makogon, 1981, 1986, 2005; Sakamoto, 2007a, 2007b), thermal stimulation (Makogon, 1981, 1986, 2005; Sakamoto et al., 2007a, b), and inhibitor injection (Makogon, 1981, 1988; Makogon and Holditch, 2005; Kawamura et al., 2006). With any method, the gas permeability and water permeability of MH-bearing sediments are important factors for estimating the efficiency of methane-gas production. Sediment permeability is generally determined by measurement using gas or liquid flow. For example, the permeability of an MH-bearing layer is measured by using gas or liquid flow through the MH-bearing sediment, which can be explored using a pressure-temperature core sampler (PTCS). The permeability of MH-bearing sediment is considerably affected by several properties of the sediment (e.g., the pore-size distribution, porosity, cementing, MH production characteristics and MH saturation). This method can be used at high pressure but is limited to samples with water-saturated pores.
Tjioe, Martin (Department of Civil and Environmental Engineering, Stanford University) | Rahmani, Helia (Department of Civil and Environmental Engineering, Stanford University) | Borja, Ronaldo I. (Department of Civil and Environmental Engineering, Stanford University)
Organosilane has been explored previously as a kaolinite fixing agent, and surface modifier to enhance adsorption of scale inhibitors. Here, self-assembled organosilane films are investigated for their potential to prevent scale deposition directly, that is without the presence of scale inhibitors. Film formation on quartz crystals is analysed using a quartz crystal microbalance, which suggests that different film structures can be created using the same organosilane molecule. Brine tests using singlecrystal quartz coupons coated with organosilane indicate that calcium carbonate scale deposition can be reduced by 66%.
Keywords: adsorption, organosilane, inorganic scale precipitation, self-assembled monolayer, quartz
Calcium carbonate and iron carbonate scales are widely observed in oil and gas production. Scale formation can be useful for corrosion control; however, excessive scale buildup can lead to severe production loss. What is called calcite scale in the field is almost always a solid solution of iron in calcite. Yet little attention has been paid to the precipitation of these mixed calcium-iron carbonate scales. As a result, knowledge of the formation and inhibition of mixed calcium/iron scales is very limited.
Normally, calcite scale formation is readily inhibited, whereas siderite inhibition is notoriously difficult. The solid-solution transition from predominantly calcite to predominantly siderite properties is unknown. Besides, although the solubility of mixed scale can differ by several orders of magnitudes from the solubility of its pure salts, scale prediction models are normally developed based on the data from pure solids. Finally, the incorporation of iron into calcite solid dramatically alters the kinetics of scale growth, as will be illustrated.
A series of experiments were performed to precipitate mixed iron-calcium carbonate (FexCa1-XCO3), ranging from calcium-rich to iron-rich. The experiments were conducted at 7.3±0.2 pH in 0.5 M NaCl at 55 oC. The work was performed with a new constant composition method, modified to handle oxygen sensitive ferrous carbonate scale and solid solutions.
Based upon the experimental results and a flux-based theoretical derivation, a new correlation in a form of a logistic function has been developed to predict the composition of FexCa1-xCO3 as a function of the aqueous composition. The model is an excellent representation for all of the experimental results, with R2 greater than 0.97. The correlation and methods developed in this work can readily be adapted to other mixed scale systems. Laboratory results will be compared with field observations and the consequences discussed.
This paper details the laboratory evaluation and product development for auniquely applied gas-lift paraffin inhibitor. Several crude oils, specific toone particular Gulf of Mexico subsea network, were characterized with respectto cloud point, pour point and paraffin content. This information was used todetermine suitable wax inhibitors to test for application into the productionfluids offshore. Cold finger wax deposition tests were performed to evaluateeight different inhibitor chemistries.
Details are given on the test methodologies used, with particular focus on thespecific evaluation to determine gas-lift suitability. Volatile flash analysiswas performed by a third party laboratory, coupled with a unique dynamicgas-lift test method, to find a suitable candidate. Of the products tested, twonew and specific formulations were developed for gas-lift applications thatdisplayed low weight loss and very little increase in viscosity.
There is very little documented in open literature on the formulations and testmethodologies employed to evaluate paraffin inhibitors for gas-liftapplication. This paper describes the most important treatment parameters anddetails on how gas-lift application was performed. This includes somesignificant learning lessons on the design and implementation of gas-liftparaffin inhibitors, as well as conclusions regarding the most appropriatedeployment parameters to avoid gunking and clogging of injection systems. Italso details the specific chemistries that can and should be used for this typeof application.
Iron is known to affect the performance of polymeric and phosphonic acid based inhibitors used to control barium sulfate scale during oil and gas production. To evaluate these effects, the performances of both types of inhibitors have been determined in the presence of iron in simulated oilfield brine. Iron adversely affected the performance of the polymer but enhanced the performance of the phosphonate inhibitor. Evaluation of blends of the two inhibitors showed improved performance compared to either type of inhibitor used separately. An optimum ratio of polymer to phosphonate was determined which achieved greater than 90% inhibition of barium sulfate formation over the range 0 - 120 ppm iron.
Scale deposition in producing wellbores is a serious problem in the industry. The problem gets worse, when the scale is caused due to barium and strontium salts. These salts are difficult to clean as they are not easily soluble in any kinds of solution or chelating agents. In case of offshore operation, the scaling phenomenon is inevitable, as sea water injection is done.
Formation of scales changes the surface roughness of the production tubing, thereby increasing the frictional pressure drop leading to a decreased production rate. Further deposition clogs the production tubing, creating hindrances for lowering tools into lower sections of the production string. In worst cases tubing replacement needs to be done, which is a capital intensive activity.
Creating a super hydrophobic surface with multi-scale nano structures on the inside of the production tubing can greatly reduce the chances of scale deposition. This surface is created on epoxy paint surfaces using a feasible dip coating process. Microstructures are created on this surface using sandblast. Then nano structures are introduced on to the micro surface by anchoring 50-100 micro-meter SiO2 particles and finally completed by dip coating with nano SiO2/epoxy adhesive solution. The hydrophobicity is further enhanced by another dip coating of a low surface energy polymer, aminopropyl. The super hydrophobic surface shows a contact angle of 167.8 degrees (Cui, Yin, Wang et al. 2009) for water, and has high stability in basic and common organic solvents.
The ions are carried in the water present in the crude. By increasing the contact angle for water, the chances of deposition of the ions that pose scaling can be reduced. This method may provide a long term solution for scale deposition especially in offshore fields where scaling incurs huge losses.