Fluid recovery after fracturing treatments in tight gas reservoirs is often critical in obtaining maximum production rates. Fluid recovery aids in washing broken fracturing fluid out of the propped fracture and restores the relative permeability to gas in the invaded matrix of the fracture face. However, recovery of fracturing fluids from the invaded matrix requires overcoming both capillary pressure-driven imbibition and the capillary exit pressure that occurs at the fracture boundary between the matrix and propped fracture. Surface active materials, such as alcohols and surfactants, are often used to reduce the surface tension, and hence the capillary pressure functions in the matrix. These materials are expected to enhance recovery of the fracturing fluid from the matrix, improving load recoveries. Modeling this process with classical reservoir simulators is not possible because they do not allow for the impact of surface tension reduction on capillary pressure functions. A previously reported simulator for modeling fracturing fluid movement has been modified to accommodate the impact of surface tension reduction on capillary pressure. This simulator uses the simultaneous solution (SS) method for solving the two-phase flow equations, followed by calculation of the movement of chemicals based on the pressure solution at each time step. A new modification to the SS method has been developed to allow proper modeling of the impact of capillary pressure reduction by surfactants.
Surfactants can reduce capillary pressure in the matrix by reducing surface tension and/or by changing the wettability of the rock surface when they adsorb on a surface. The classical SS method does not maintain proper "mass balance?? when surfactants are allowed to change the capillary pressure; the reason for which is demonstrated in this work. The new modification allows surfactants to impact capillary pressure through surface tension reduction and wettability changes.
Samuel, Elsamma (Schlumberger Well Services) | Shaikh, Ahmed Karim (Brunei Shell Petr. Sdn Bhd) | Queiros, Joao GR (Schlumberger) | Yong, Yin-Chong (Brunei Shell Petr. Sdn Bhd) | Samuel, Mathew | Chan, Keng Seng
Improving oil and gas production from the Brown Fields is now more important than ever to the operating companies, as the oil price remains record high. Matrix stimulation is often preferred as it could generate additional production gain with relatively low level of investment. In the recent acidizing campaign in Brunei, a particular challenge was the flowback of tubing pickling and spent acids, and neutralization of the spent acid on the surface. A series of effective methodologies for the stimulation of offshore multilayer sandstone oil reservoirs was implemented. The chemistry and art of four different acidizing methods involving Tubing Pickling, Bullheading, Diversion and Coiled Tubing placement were used. Stimulation of over forty wells utilizing different acid systems and procedures resulted in noticeably different production gains. The short and long term results are correlated with the stimulation procedures and practices. The present paper describes a comparison of procedures and production gains during these acid stimulation treatments. The cost, logistics and operational constraints due to specific Brunei offshore environment and conditions will also be discussed. Post-treatment production gain is correlated with the efficiency and timing of the flowback process. Use of computer-based virtual laboratory tool for the fluid selection, coreflow laboratory testing for the fluid optimization at downhole conditions and evaluation of fine migration tendencies were investigated before the treatment. The results were compared with the one from other operators in the same environment and reservoir conditions. Review of post acidizing results came up with recommendations and lesson learnt for future campaigns. This effort will certainly enhance the success ratio of the sandstone acidizing treatments. Significance: Developed lessons learnt to increase the success ratio of sandstone stimulations.
Thermosetting resins are employed in a wide variety of oilfield applications. The development of dilute resin formulations offers several advantages over conventional resin systems and new resin applications are making increasing use of dilute formulations. Knowledge of the thermodynamic properties of the resin system is essential to ensure that they perform as expected. We report here on the use of nuclear magnetic resonance, NMR, to measure activation energies, enthalpies, entropies, and frequency factors for the curing of a diglycidylether bisphenol A epoxy resin with a modified cycloaliphatic amine hardener. Results calculated with this technique are presented here and are in good agreement with values calculated using more conventional techniques.
Voordouw, Gerrit (University of Calgary) | Buziak, Brenton (University of Calgary) | Lin, Shiping (University of Calgary) | Grigoriyan, Alexander (University of Calgary) | Kaster, Krista M. (University of Calgary) | Jenneman, Gary Edward (ConocoPhillips Co) | Arensdorf, Joseph John (Baker Petrolite)
The production of sulfide by sulfate-reducing bacteria (SRB) in oil and gas fields causes problems including enhanced corrosion risk, reservoir plugging and deterioration of product quality. Injection of nitrate or nitrite stimulates heterotrophic nitrate-reducing bacteria (hNRB), which compete with SRB for oil organics, such as volatile fatty acids (VFA). Nitrate also stimulates nitrate-reducing, sulfide-oxidizing bacteria (NR-SOB), which lower sulfide levels. Nitrite is a strong and specific inhibitor of the SRB enzyme responsible for sulfide production, whereas nitrate does not inhibit SRB.
Hence, injection of nitrate or nitrite can prevent or remediate problems in the oil and gas industry caused by SRB activity, provided hNRB and NR-SOB are present.
A survey of 8 oil fields, 2 gas storage reservoirs and an oil storage tank indicated that SRB and hNRB were widely distributed, whereas the distribution of NR-SOB appeared more limited. The SRB and hNRB were able to use lactate, as well as VFA as electron donor for sulfate or nitrate reduction. However, the order of use of VFA components appeared to differ with acetate being used preferentially by hNRB and propionate and butyrate being used preferentially by SRB. The production of nitrite by hNRB and NR-SOB varied greatly with quantitative conversion of nitrate to nitrite (up to 30 mM) being observed in one case; the nitrite formed was then reduced further. Samples from a high temperature North Sea oil field had thermophilic SRB, but no hNRB or NR-SOB activity, causing sulfide production to be inhibited by nitrite only. Although nitrite appeared to react chemically with sulfide under these conditions, causing all nitrite to disappear within 100 h, the observed inhibition was long-lasting (>500-1500 h). Hence, nitrite can be used successfully to control SRB activity in fields where hNRB and NR-SOB are absent.
In summary, it appears that many oil and gas fields contain hNRB and NR-SOB populations, which are activated upon injection of nitrate or nitrite, allowing sulfide remediation in situ. Characterization of these populations as described in this paper may allow prediction whether these injections will be successful and whether use of nitrate or of nitrite is preferred.
The periodic cleaning of the bottom of crude oil storage tanks in vessels, terminals and refineries has become a big problem for industrial maintenance, principally due to the temporary inoperability of the equipment and the high environmental impact caused by the conventional treatments used. The storage of crude oil in large tanks invariably creates a gradual deposition process of organic sediments of high molecular weight.
PETROBRAS has developed a thermochemical method aimed at removing wax deposits in submersed oil pipelines, wax damage in production reservoirs and petroleum sludge removal from storage tanks.
This work presents the chemical treatment performed inside an oil storage tank located onboard an oil tanker as well as the laboratory methodology for the organic deposit physical-chemical characterization, kinetics of reaction, physical simulation, treatment dimensioning and operational treatment, aimed at the removal of 800 M3 of organic deposit.
The thermochemical method consists of a chemical reaction between two nitrogen salts that produce a strong exothermic chemical reaction. The heat produced by the reaction, together with the turbulence due to the generation of a large volume of nitrogen and the solvency,dispersed the initially solid compacted sludge at the bottom of the tank. The heat of the solution, estimated at 90oC, in contact with the sludge, irreversibly melted the organic fractions according to the previously studied phases diagram.
The method demonstrated itself to be efficient, safe and of low cost, when compared to existing classic methods. The process financial balance showed that the cost of the oil recovered from the organic deposit paid for the investment in chemical reagents and operational facilities.
Selecting an effective scale inhibitor for squeeze application at 170°C is no simple task. The traditional thermal stability test by aging the chemical in bulk is often perceived to be too harsh. This results in many promising products being rejected due to their apparent degradation at temperature. The alternative of conducting aging test inside core materials, hence more representative to the downhole conditions, is NOT a novel idea. However, no definitive data is available to date that can substantiate such argument and quantify the difference between the two methods. This is mainly due to the difficulties and complexity to conduct such an experiment at high temperature over a long period of time. In this paper, the results from a recent investigation are presented. It describes the detailed procedures during the planning and execution stages, lessons learnt and pitfall to avoid. A scale inhibitor was aged using two different methods, one in bulk as commonly practiced in the industry and one inside a sandstone core. The aging period varied between 45 days as in the bulk and 110 days as for the last desorbed sample from the core. The samples which were aged inside the core retained much of their inhibition efficiency whilst that aged by the traditional method (bulk) lost nearly all its effectiveness. These results CLEARLY demonstrate that the conventional method of thermal aging in bulk is unrepresentative and that the loss in performance can be quantified. A NOVEL finding from this study is the evidences of an unexpected relationship between desorption and inhibition effectiveness. The findings from this study will have great impact on selecting chemicals for HT applications. More so in those environmental sensitive regions where the use of 'yellow' (biodegradable) squeeze chemicals are mandatory. Many of these have been discarded due to their apparent thermal degradation which is now proved to be unrepresentative.
During the 1980's, studies initiated to resolve problems due to the activity of sulfate-reducing bacteria in oilfield systems were instrumental in the early recognition of the importance of biofilms in natural environments, the use of radiotracers to measure bacterial activity, the application of molecular techniques to study nonculturable bacteria and the detection of previously unknown Archaea in subsurface aquifers.
Over the past 15 years, however, oilfield microbiology practices have not kept pace with other fields of environmental microbiology research and now the ideas and practices applied in the oilfield lag significantly behind the most recent scientific advances. This is despite the fact that the oil industry is currently attempting to control very diverse and extensive sulfide producing microbial populations by the application of nitrate to bring about a shift in the population dynamics in a process of biological competitive exclusion.
Environmental microbiology is now in the midst of a revolution in the understanding of the marine and subsurface microbial world, much of which is resulting in completely new concepts of the interaction between microbes and the environment and vice versa. These advances must be recognized and wherever possible incorporated into oilfield microbiology technology.
This paper describes how the application of even a few of the recent advances in environmental microbiology offers a huge potential to improve our understanding of control and remediation of sour reservoirs using nitrate treatments.
This paper presents the results of a data-driven field modeling (DDFM) evaluation applied to a high-temperature reservoir in Australia for the purpose of determining the significance of chemistry, reservoir, well, and hydraulic-fracture characteristics on well production. The DDFM approach has identified key production drivers for a gas-well field in Australia. This information has been useful to explain hydraulic fracture well production and provide guidelines for future fracture stimulation success.
A DDFM process was used to develop a model for 32 wells completed in a complex, 250 to 350°F gas reservoir in Australia. This type of modeling technique uses data from the field, including chemical formulation, geology, reservoir, well, completion, hydraulic-fracture stimulation, and production results. The data is integrated into a common format and resolution, then visual and statistical evaluation is performed. Relevant correlations and useful trends are noted. Next an effort is made to develop a predictive model that can be used to provide an overall explanation as to what parameters drive production in the well field. Or, in effect, derive a high-level understanding about the effect of the fracturing process on the reservoir. This is accomplished by the use of data modeling/optimization technologies, including artificial neural network (ANN) and genetic algorithms.1-3 The resulting ANN model can then be used to evaluate the production associated with various hydraulic fracturing scenarios and/or characteristics. Validation of conclusions and/or resolution of difficult interpretation issues are done by detailed evaluation and modeling of key wells.
Hydraulic-fracture stimulation scenario evaluations performed by the ANN model have yielded some expected and some unexpected results. As expected, reservoir characteristics such as pay thickness, porosity, and water saturation have a dominant effect on well production. What was unexpected is the significance of well operations and stimulation fluid chemistry on well production. The practice of killing the well after stimulation and using inappropriate perforation techniques can reduce gas production by as much as one-half, while the use of a high-temperature gel breaker in combination with a reduction in base-gel polymer load can provide a 67% increase in production.
Purification of produced water by zeolite membranes is a novel technology reported recently for reclamation of produced water for beneficial use. Because of the extremely stable chemical, mechanical, and thermal properties, zeolite membranes show great advantages in difficult situations such as operations in a strong solvent environment, or those requiring high temperatures and high pressures. In this paper, we reported reverse osmosis (RO) permeation of solutions containing dissolved salts on a zeolite membrane. The influencing factors, including operating pressure, temperature, and ion concentration, on the RO performance of zeolite membranes are investigated. Potential application of the zeolite membrane technology in large-scale produced water purification is also discussed.
Typical gel polymer treatments to treat fractured rock consist of injecting inline mixed gelant into the reservoir for times usually much longer than the bulk gel time of the gelant. Flow experiments were conducted to determine the effect of shear on the flow properties of the gelant for durations greater than the bulk gel time. Inline mixed gelant was injected through a 1031-ft long tube to simulate a fracture. Flow resistance increased down the tubing to steady values indicating gelation of the flowing system. Similar flow experiments were conducted by injecting preformed gel through the tubing. Flow resistances decreased down the tubing to steady values indicating breakdown of the gel structure. Flow resistances at the steady downstream sections were higher during the injection of inline mixed gelant compared to injection of preformed gel and both were much lower than literature values determined where preformed gel was injected through short fractured rocks and short lengths of tubing. Gel samples underwent syneresis after they were formed during shear flow in the tubing and in a rheometer. Interpretations of flow resistance data from injection of inline mixed gelants and preformed gels in long tubing are presented.