Thesis (Ph. D.)--University of Oklahoma, 1993. / Includes bibliographical references (leaves 253-267).

<p> Scale control in oilfield operations is the intervention technique deployed to remove the assemblage of solid deposits from the surface of oil and gas well tubular and associated equipment. Common mineral scales that plague production operations are Barium Sulfate, Strontium Sulfate, Calcium Carbonate, and Iron Sulfide. Some of these scales can be dissolved with acid while others cannot. Barium Sulfate which is common at perforations and downstream of chokes is notorious for its resistance to chemical treatment because of its low acid solubility.</p><p> This study investigates the effect of different chemical inhibitors on Barium Sulfate scale. The tube blocking test is widely used to evaluate the efficiency of these chemical inhibitors. Although the principal method of investigation was the tube blocking apparatus, preliminary analysis and optimization were done using the static bottle test and a scale inhibitor performance prediction software called French Creek. The static bottle test was used as a screening method whereby ionic interaction between anionic, cationic and inhibitor solutions gave a clear difference in turbidity or otherwise. The French Creek interface allowed multiple iterations over a range of operating conditions and treatment options. A tube blocking apparatus was constructed to simulate the buildup of scale deposits in an oil pipeline. The set up was operated at pressure and temperature of 100psi and 90&deg;C respectively. Of all the additives tested, phosphonate based chemical had the lowest minimum inhibitor concentration. </p>

Microannular gas flow in the wellbore is known to be one of the major reasons for Sustained Casing Pressure (SCP). Low success rate (under 50%) of costly remedial cementing operations and increasing difficulty in sealing off problematic areas motivated the industry to look for more practical remediation solutions. Expandable casing technology is one of those new proposed techniques. A bench-scale physical model tested the potential of expandable casing technology for remediation of microannular gas migration. The composite samples with pipe-inside-pipe cemented annulus were designed to simulate a wellbore system including a pre-manufactured microannulus on the inner pipe/cement interface. Multi-rate flow-through tests with nitrogen gas first evaluated the permeability and the size of the pre-manufactured microannulus. The post-expansion flow-through experiments tested the ability of pipe expansion in sealing the microannular gas flow. The effects of expansion on properties and structure of the cement were investigated by microindentation, optical microscopy, thermogravimetric analysis (TGA) and inductively coupled plasma (ICP) mass spectrometry. As observed with optical microscopy, the dissolution of unhydrated clinker grains during expansion is coupled with pore collapse within the cement sheath. Information obtained by microindentation showed that the cement sheath loses the integrity initially after expansion but regains most of the mechanical properties after a period of rehydration. Most important, multi-rate gas flow-through experiments showed that all three expansion ratios of 2%, 4% and 8% were successful in sealing the microannular gas flow. The seal was confirmed immediately and then 24 hours and 60 days after expansion. The findings in this research give solid support to the potential of expandable casing technology for remediation of microannular gas migration. Cement pore water propagation is the most likely driving force behind a successful expansion, one that is not an obstacle in subsurface conditions and also makes an ideal environment for cement rehydration post-expansion. Cement integrity should not be compromised by pipe expansion after certain period of rehydration. Finally, the research showed that expansion technology could be used during all operations in vertical and horizontal wells, whether injection or production wells, to mitigate well leaks caused by gas migration.

<p> The average pore size in producing unconventional, liquids-rich reservoirs is estimated to be less than 100 nm. At this nano-pore scale, capillary and surface disjoining force interactions, such as van der Waals, structural, and adsorption, affect the phase behavior that is not considered to be significantly, different than in conventional reservoirs. In this dissertation, a comprehensive discussion of the thermodynamics required to model phase behavior of unconventional, liquids-rich reservoirs is presented. Three oil compositions from different unconventional reservoirs are used to generate results. </p><p> The impact of confinement manifests itself in the form of reduction of the liquid pressure at which the first gas bubble forms when compared to the bulk fluid measurements in PVT cells. It is shown that the suppression of the bubble-point pressure impacts the saturated portion of the liquid formation volume factor and extends the undersaturated portion of the curve. The equilibrium gas composition is different for each supersaturation level and the gas is composed of lighter components as the supersaturation, i.e., the bubble-point suppression, increases. The minimum radius of the pore that is required to form a specified size bubble is also investigated and the range of pore sizes required under different assumptions is reported. </p><p> The impact of this phase behavior deviation on the flow of confined fluids is investigated using a black-oil simulator, COZSim, which evaluates gas and oil fluid properties at corresponding phase pressures. The simulator was independently developed in a DOE project with the capability to incorporate the findings of this research. The results of the analysis show that there is a difference in gas production and gas saturation distribution in the reservoir with and without the confinement impact on the PVT properties. The produced GOR is lower when the confinement is considered due to the bubble-point suppression. These results indicate that the use of bulk fluid measurements in modeling and predicting the performances of nano-porous unconventional reservoirs may result in significant underestimation of the reservoir potential. </p>

Although water coning is well understood, it is difficult to control in field operations resulting in low recovery and large volumes of waste produced water. A solution - proposed here - is a multi-functional well with the in-situ bottom water drainage and injection installations - Downhole Water Loop (DWL). Theoretically, DWL greatly improves well performance (for example, a two-fold increase of DWL wells water drainage rate would increase the critical (water-free) oil rate by 80%). However, DWL has practical limitations that must be quantified for actual well design. The objective of this work is to: (1) find maximum water drainage rate to ensure separation of a small amount of under-drained oil from the drainage water; (2) learn how the small oil contamination would impact water injection and how to set criteria for oily water disposal to the bottom aquifer; and, (3) develop a method for assessing feasibility of DWL for oil reservoirs with bottom-water coning problem. Counter-current oil water separation experiments have been to simulate the flow of oil droplets in the downhole water looping section of DWL wells. From the results, an analytical model calculates the maximum water drainage rate that prevents carry-over of oil by the injection water. Aquifer injectivity decline is described by a mathematical model based on mass balance of oil phase in the injected water by considering the effects of oil droplets capture due combined effect of advection, dispersion and adsorption (ADA model) coupled with the two-phase relative permeability relationship. For comparison, a two-phase flow model based on the Buckley-Leverett theory describes aquifer permeability decline during oily water injection process. The two models are in a good agreement for linear flow and excellent agreement for radial flow. Consequently, the aquifer permeability damage is converted to time-dependent skin factor and injection pressure. A comparison of the injection and fracturing pressure gives an estimate of the well stimulation cycle and a criterion for screening reservoir-aquifer candidate for DWL. In order to assess DWL feasibility, a dimensionless model of movable oil recovery vs. seven scaling groups has been built using the inspectional analysis method and multivariable regression technique. The model is used as a final step in the five-step procedure for finding good reservoir candidates for DWL application. Six real reservoirs were used to demonstrate the procedure with three reservoirs becoming good candidates for DWL technology.

Low salinity and composition effects in improving oil recovery in sandstone reservoirs are known. However, these effects have not been thoroughly studied for the carbonate reservoirs. Because of the lack of the clay minerals in the carbonate rocks, the mechanisms for the improved oil recovery with low salinity, brine composition, and temperature may not be the same as those for sandstones. This experimental study attempts to investigate the effects of low salinity, brine composition, and temperature on wettability and oil recovery in a dolomite reservoir. Also, it is attempted to confirm that wettability alteration is the main mechanism for improvement of oil recovery. The experiments for this study were performed at both ambient and reservoir conditions as well as at a temperature of 250°F using two different techniques, Dual-Drop Dual-Crystal (DDDC) and coreflooding. Water-advancing contact angle was measured using the DDDC technique to characterize reservoir wettability with different salinities including twice, 10, 50 and 100 times diluted brines. Also, the effect of brine composition on wettability was investigated with Yates synthetic brine, Yates synthetic brine without sulfate, and brines containing sulfate in different concentrations. In addition, the effect of temperature on wettability was investigated using DDDC technique. Coreflood experiments were carried out using a dolomite core to determine aging time, to measure the oil recovery, and to confirm whether an optimal salinity brine and an optimal composition of brine obtained contact angle measurments improve the oil recovery compared with Yates synthetic brine. Oil-water relative permeabilities were generated by history matching the oil recovery and pressure drop data obtained from the coreflood experiments. The experimental results showed that the wettability was altered from strongly oil-wet to intermediate-wet by diluting the Yates synthetic brine by about 50 times and increasing the amount of sulfate in Yates synthetic brine from 2.2 g/l to 4.4 g/l. Also, increasing the temperature to 250°F had a significant effect on wettability and changed the wettability from oil-wet to intermediate-wet. Coreflood results confirmed the wettability alteration to intermediate-wet and also demonstrated improvements in oil recovery induced by the optimal salinity and optimal brine composition.

The use of foams can be found abundantly in many applications in a wide range of industries, including oil and gas industry. Although understanding foam flow behavior is crucial for the optimization of such applications, the complex flow behavior of foams has been a major challenge. Recent experimental studies with surfactant foams presented a new way to characterize foam flow characteristics by using two flow regimes: the low-quality regime showing either plug-flow or segregated-flow pattern, and the high-quality regime showing slug-flow pattern. This study consists of three main components: (1) experimental investigation of foam rheology in pipes; (2) building up of a new foam model consistent with lab-measured experimental data; and (3) use of the model in petroleum drilling hydraulics modeling and simulation. The major outcome of this study can be summarized as follows. First (Part 1), by conducting foam flow experiments in pipes, this study shows the concept of two foam-flow regimes is still valid and effective not only with surfactant foams but also with foams in the presence of additives such as polymers and oils. This finding is important because many field applications of foam flow involve some levels of additives. Second (Part 2), this study for the first time presents how to build a foam model which is consistent with two foam-flow regimes evidenced by experimental data. The model requires four model parameters two parameters to capture rheological properties (e.g. consistency index and flow behavior index, if power-law rheology is applied) and two parameters to define the dependence of foam rheology to gas and liquid flow rates in both foam flow regimes. Third and last (Part 3), the significance of this model is verified by implementing it into existing foam drilling hydraulics calculations in a 10,000 ft vertical well in which foams are injected down into the drill pipe, through the drill bit and circulated up to the surface along the annulus. The results show that this new foam model equipped with two flow regimes is advantageous over the conventional foam model especially when foams become dry and unstable in the well, improving the accuracy.

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No description available.

Currently employed methods for treating produced water do not consistently meet regulatory limits on oil and grease discharge concentrations. Experiments with different produced waters using tubular, crossflow, ultrafiltration membranes demonstrated that oil and grease concentrations less than 14 mg/l (well below current regulatory limits) could be achieved. Ultrafiltration experiments on produced water and model oil emulsions demonstrate that virtually all colloidal organic materials are rejected by the membrane, while dissolved organic materials pass through it. The membrane rejects precipitated iron and suspended solids. Permeate flux behavior and the effectiveness of different cleaning procedures vary significantly among produced waters. Generalizations on permeate flux performance during ultrafiltration treatment of produced water do not appear to be warranted. Permeate flux ranged from 73 to 306 l/m$\sp2$-hr depending on the produced water source and the cleaning procedures. Pilot studies on specific produced waters may be necessary to insure this process' applicability.