Telang, Milan (Kuwait Oil Company) | Al-Matrook, Mohammad F. (Kuwait Institute for Scientific Research) | Oskui, Gh. Reza (Kuwait Institute for Scientific Research) | Mali, Prasanna (Kuwait Oil Company) | Al-Jasmi, Ahmad (Kuwait Oil Company) | Rashed, Abeer M. (Kuwait Institute for Scientific Research) | Ghloum, Ebtisam Folad (Kuwait Institute for Scientific Research)
Asphaltene deposition problems in Kuwait have become a serious issue in a number of reservoirs during primary production in different fields, resulting in a severe detrimental effect on the economics of oil recovery. Hence, one of the mitigation approaches in the field is using remedial solvent treatments, such as Xylene or Toluene, which is very costly and harmful to the environment.
Kuwait Oil Company (KOC) is planning to produce from asphaltinic Marrat wells that have been shut down due to low bottom-hole pressure (BHP), by artificial lifting technique using an Electric Submersible Pump (ESP) supported with continuous chemical injection, as a pilot. The main objective of this study was to investigate in the lab the effectiveness of various concentrations of toluene/diesel (T/D) mixtures on Marrat reservoir fluid in order to mitigate asphaltene deposition problem during the actual pilot implementation.
Preliminary screening tests were conducted on the surface oil sample using Solid Detection System (SDS) "laser technique?? to determine the optimum dose of the T/D mixture ratio. The results showed that pure diesel accelerated the asphaltene precipitation; however, mixing T/D inhibited the precipitation process. Series of pressure depletion tests was then conducted on live oil , single phase samples, to determine the Asphaltene Onset Pressure (AOP) with and without adding various ration of T/D solvents at different temperatures from reservoir to surface conditions.
The results revealed that using 15% (by volume of oil) from the (50T:50D) mixture reduced the AOP close to the bubble point pressure. Furthermore, the amount of the precipitated asphaltene was physically quantified using a bulk filtration technique. It was observed that, based on blank sample, the wt% of the precipitated asphaltene was minimized at the AOP and maximized at the bubble point. However, using the recommended mixture of 50T/50D, the amount of asphaltene that precipitated was almost negligible. Therefore, from a health, safety, and economic point of view, this study recommends using a low dose of 7.5% (by volume of oil) from toluene mixture with diesel (50%:50%) rather than using pure toluene to prevent the precipitation.
This paper aims to study the miscibility features of CO2 miscible injection to enhanced oil recovery from Thani-III reservoir. A Comprehensive simulation model was used to determine multi contact miscibility and suitable equation of state with CO2 as a separate pseudo component using one of the industry's standard simulation software. Experimental PVT data for bottom hole and separator samples including compositional analysis, differential liberation test, separator tests, constant composition expansion, viscosity measurements and swelling tests for pure CO2 were used to generate and validate the model. In addition to that, simulation studies were conducted to produce coreflooding and slimtube experimental models, which were compared with the conclusions drawn from experimental results. Results of this study have shown comparable results with the lab experimental data in regards to minimum miscibility pressure (MMP) calculation and recovery factor estimation, where the marginal errors between both data sets were no more than 7% at its worst. Results from this study are expected to assist the operator of this field to plan and implement a very attractive enhanced oil recovery program, giving that other factors are well accounted for such as asphaltene deposition, reservoir pressure maintenance, oil saturation, CO2 sequestering and choosing the most appropriate time to maximize the net positive value (NPV) and expected project gain.
Cinar, Yildiray (The University of New South Wales) | Arns, Christoph (The University of New South Wales) | Dehghan Khalili, Ahmad (The University of New South Wales) | Yanici, Sefer (The University of New South Wales)
Resistivity measurements play a key role in hydrocarbon in place calculations for oil and gas reservoirs. They are a direct indi-cator of fluid saturation and connected pore space available in the formation. Carbonate rocks, which host around half of the world's hydrocarbons, exhibit a wide range of porosities with scales spanning from nanometres to centimetres. The often sig-nificant amount of microporosity displayed by Carbonate rocks emphasizes the necessity of an adequate characterization of their micro-features and their contribution to hydrocarbon in place. In this paper we examine upscaling methods to probe for-mation factor of a fully saturated carbonate sample using an X-ray CT based numerical approach and compare to experimental measurements.
Three-dimensional high-resolution X-ray CT enables the numerical calculation of petrophysical properties of interest at the pore scale with resolutions down to a few microns per voxel. For more complex and heterogeneous samples however, a direct calculation of petrophysical properties is not feasible, since the required resolution and a sufficient field of view cannot be obtained simultaneously. Thus an integration of measurements at different scale is required. In this study a carbonate sample of 38mm in diameter is first scanned using the X-ray CT method with a resolution of 26µm. After accompanying experimental measurements on the full plug, four 5mm plugs were drilled vertically from this sample and X-ray CT images of these plugs acquired at resolutions down to 2.74 µm. We calculate the porosity of the sample (macro- and micro-porosities) using the phase separation methods and then predict the formation factor of the sample at several scales using a Laplace solver. The formation factor is calculated by using a general value of m=2 as cementation factor for intermediate porosity voxels. We compare to experimental measurements of formation factor and porosity both at the small plug and full plug scale and find good agreement.
To assess the degree of uncertainty of the numerical estimate, we probe the extent of heterogeneity by investigating the size of a representative elementary volume (REV) for formation factor. We find that for the considered heterogeneous carbonate sam-ple, formation factor varies considerably over intervals less than a centimetre. Our results show that this variation could be explained by different cementation exponents applied at the micro-voxel scale, with the exemption of one plug, for which the cementation exponent would have to be unreasonably low. These cementation factors are derived by direct comparison be-tween numerical simulation and experiment. We conclude that for one plug an error in experimental measurement might have occurred. The numerical approach presented here therefore aids in quality control. Excluding this plug in the upscaling proce-dure improves the agreement with the experimental result for the whole core while still underestimating formation factor. Al-lowing for a constant m=2 in the simulation at the small scale and using directly the resulting relationship between porosity and formation factor in the upscaling process leads to an overestimation of formation factor.
Shale gas reservoirs have become financially attractive upon more efficient utilization of technologies such as horizontal drilling and hydraulic fracturing. In order to better identify such reservoirs, estimate their production potential, as well as
device optimum drilling and fracturing strategies, a detailed understanding of the connection between gas shale macroscopic mechanical and petrophyscal properties and microstructure is highly valuable. Since a high fraction of both pores and grain
structures in gas shales are of nanometer sizes, this requires advanced experimental techniques beyond what has commonly been applied on more conventional coarsely grained reservoir rocks. We present a study of the Mancos outcrop shale where we combine results from state-of-the-art nano tomography with results from standard rock mechanical, petrophysical, and geochemical testing. In addition to providing the first detailed investigation of the Mancos shale on the nanometer pore scale, this multi-scale analysis contributes to bridging the gap between small- and large-scale gas shale descriptions - and to establish the role of nano tomography in relation to more standard rock testing procedures. Our study revealed that the Mancos shale is marginally mature (%Ro ~ 0.66-0.70), gas prone and has a total organic content of 1.0-1.3 wt%. It is observed that even if the porosity of the organic matter itself is very low, organics are found in or around all analyzed fractures and voids in the Mancos sample. Large fractures parallel to bedding are observed to be organic-rich, potentially enabling the soft organic material to serve as a preferential weak plane when the rock is subjected to mechanical stress. This may be reflected in the observed significant strength anisotropy of about 60% deduced from rock mechanical tests on the same material. It is also suggested that nano/microfractures influence the measured acoustic properties, which appear consistent with those of other organic rich shales. Thus, knowledge of the detailed nanostructure, especially the distribution of organic matter, its porosity and its interface towards other solid phases, may be beneficial when attempting to predict shale macroscopic mechanical and petrophysical properties. Knowing these simplifies the process of identification and characterization of shale gas prospects, aswell as the subsequent drilling and production.
It is found that in the deepest part of Cooper Basin (Permian section in Nappamerri Trough) in South Australia, two shale formations, Roseneath and Murteree have potential to be shale gas reservoirs. However, a comprehensive petrophysical evaluation has not been carried out so far. The free porosity among minerals, pore throat geometry, surface area and structure of micro pores for adsorption and diffusion of gas in these formations have not been well understood.
Two core samples from two wells (Della 4 and Moomba 46) were selected to evaluate mineralogy, free porosity and other petrophysical characterization. Since routine core analysis is not capable of petrophysical characterization of these very tight rocks, the latest technology of image scanning and processing of QEMSCAN (Quantitative Evaluation of Minerals using Scanning Electron Microscopy) and Computerized Tomography (CT) scanning have been used. QEMSCAN is a novel technology to process images from electron microscope to measure size and distribution of different minerals in a rock sample. QEMSCAN when combined with CT scanning can significantly enhance shale rock characterization and reservoir quality assessment. In this study, the main goal is the evaluation of total free porosity, micro pores and natural network of micro-fracture systems in our ultra fine samples.
Based on QEMSCAN analysis, it is found that the sample of Murteree shale has the mineralogy of quartz 42.78%, siderite 6.75%, illite 28.96%, koalinite 14.09%, Total Organic Content (TOC) 1.91 wt%, and pyrite 0.04%, while rutile and other silicates minerals were identified as accessory minerals. Total free porosity is found to be 2 percent. The free porosity is largely associated with clay minerals which shows intergranular linear, isolated and elongated wedge shaped pores. SEM images from the same core sample also show that the pores are mainly present in clay rich zone. QEMSCAN maps have revealed the location of lamination, high and low porosity zones as well as high and low sorption areas. In CT scanning, the porosity found in QEMSCAN, was not identified; however, a network of micro-fracture system in Murteree shale sample is identified.
From the point-of-view of a solutions provider the wastewater treatment should be straight forward: once given the composition of the feed and the required composition of the effluent, today's technology allows formulating a set of solutions which best meets the operator's and the regulatory criteria.
The problem with wastewater in the unconventional gas exploration and production operations is that there are large volumes to be handled and treated. To add complexity, composition varies for the same well in time and varies even more from area to area of development. Also, the requirements for the cleaned fluid vary from operator to operator and by region. Moreover, management of the water based fluids is under the pressure and scrutiny of various regulating agencies: public, privately, or governmentally run. All these constraints make the vetting of treatment methods and technologies to be a very dynamic and intensive process.
Our findings during the process of formulating a set of solutions shows that a deep understanding of the problems, combined with close collaboration with the operators and regulators along with solid basic engineering practices are the key to success.
Our experience would benefit the new developments in other unconventional exploration and production area in Asia by showing the steps that were undertaken to insure solutions are up to the highest standards.
The process of finding and testing various waste water treatment technologies to formulate a flexible comprehensive set of methods will be described. Laboratory results of various samples of water will be presented as well as the challenges that were overcome for obtaining consistent, reliable analytical data. The oilfield tough requirement presented to new technologies translates as: rugged, flexible, mobile, and low cost.
Water is a precious commodity that is needed in all human activity and for life in general. The Oil & Gas industry uses and generates large quantities of this commodity (Produced Water Volume Report). On average, for every barrel of oil produced there are eight barrels of associated wastewater. Increasing the efficiency of water usage and improving its management is both a high priority among E&P companies and a subject of intense scrutiny for the communities in which they operate.
Water Necessity in Developing Areas
The availability of suitable water for hydraulic fracturing and the means for environmentally responsible water recycling and disposal are critical for sustainable unconventional development. Produced water that comes to the surface during oil and gas recovery presents a challenge for Marcellus drillers because of the scarcity of injection wells in the Appalachian region. Other areas, like West Texas (Permian Basin or Eagle Ford Shale) do not lack for disposal options but do suffer due to the arid climate and depletion of ground water resources.
The precipitation and deposition of paraffin wax during production, transportation and storage of crude oil are common problems encountered by the majority of oil producers around the world. During the last decade, the Barrackpore oilfield in Trinidad has reported wax deposition on nineteen (19) of its wells. This condition has been exacerbated due to the reduction of temperature, pressures and losses of gas which have allowed wax to separate from the crude oil, precipitate and deposit in the walls of tubings, thereby reducing their diameter and restricting the flow of oil through the system. The situation represented a serious problem for Petroleum Company of Trinidad & Tobago (Petrotrin), because it caused a reduction in the production levels and significant economic losses. This study was based on the necessity to find feasible solutions to minimize this problem. The research was focused to determine if there was influence of the resin/asphaltene ratio on wax deposition under laboratory conditions, to start an understanding process of the causative factors of these depositions. In addition, the influence of two (2) different wax inhibitors were studied for comparison, since it is understood they may behave as resins peptizing the asphaltene particles and keeping them in solution. To ensure the validity of this investigation, extensive bibliographical reviews were undertaken, followed by numerous laboratory tests such as SARA analysis, Cloud Point Tests and Wax Content Tests as methods to evaluate the crude oil and its behaviour under various conditions. The results showed that wax and asphaltene content are the controlling factors in the precipitation and depositions processes respectively.
Water flooding is the hinge pin for Gemsa Oil Field. Water injection is supplied from shallow water supply wells. Compatibility tests had indicated probable deposition of calcium sulphate scale on surface and subsurface production equipment. Calcium sulphate scale has been recognized to be a major operational problem. The bad consequences of scale formation comprised the contribution to flow restriction thus resulting in oil and gas production decrease. The nature of calcium sulphate scale is very hard and can't be dissolved with known dissolver. Sister companies that has similar problem were always going to the mechanical remover options.
Extensive lab and field work was conducted to determine the suitable chemicals to dissolve calcium sulphate scale.
This paper describes the development and field application of chemical treatment to remove scale in an offshore 8?? production line in Gemsa oil field. Continuous precipitation of calcium sulphate scale caused partial plugging of the pipeline. This partial plugging created a back pressure on production wells which decreased the productivity. The field production has been decreased to almost one tenth of the normal field production level(1).
A thorough investigation was conducted to identify the composition and location of the scale, in order to recommend a suitable chemical to remove the scale, and to assess the effectiveness of the treatment method in the field.
Based on extensive lab studies, SAG-01 was tested and applied in production line to remove the scale efficiently, the program was designed taking into consideration the nature of the scale.
The treatment program included three - staged process:
1. The use of an organic solvent
2. The main treatment (SAG-01).
3. The post flush stage (injection water),
The job results were outstanding, where as
1- Production increased by about 2,000 BOPD
2- Launcher pressure dropped by about 350 psi.
3- Decrease the back pressure on our producing wells.
4- Additional producing wells into production.
5- Efficient cost /Bbl.
Sayed, Mohammed Ali Ibrahim (Texas A&M University) | Zakaria, Ahmed Salah El Deen (Petroleum Engineering Texas AM University) | Nasr-El-Din, Hisham A. (Texas A&M University) | Holt, Stuart Peter (Akzo Nobel Surface Chemistry LLC) | Almalki, Hassan (Qatar Petroleum)
The main objective of well stimulation has been to create wormholes or fractures in order to bypass the damaged zone and enhance the permeability in the near-wellbore area. Regular HCl was the main stimulation fluid. However, at high temperatures, both reaction and corrosion rates become very high and regular HCl loses its advantages. There are many alternatives for regular HCl; emulsified acid is one of the available alternatives for regular HCl.
In the present work, an emulsified acid system was used formulated using a cationic surfactant. This system was tested using reservoir cores obtained from a carbonate reservoir. The core samples were analyzed using CAT scan to study the presences of vugs or channels, and to determine the presence of anhydrite. Small samples of the cores were analyzed using the SEM technique. A series of core flood tests were conducted using 15 wt% HCl emulsified acid systems formulated using 1.0 vol% emulsifier. The acid volume fraction was 0.7, and all experiments were performed at temperature of 220ºF. The acid injection rate ranged from 1.0 to 10 cm3/min. After acid treatment is accomplished, the cores were CAT scanned to study the number and distribution of wormholes. Samples of the effluent fluid were collected during the core flooding experiment. These collected samples were analyzed using the ICP, to determine the calcium and magnesium concentrations.
The CAT scan of the cores obtained from a carbonate reservoir showed a great heterogeneity. The static test for solubility of rocks in regular 15 wt% HCl, indicated that the rocks has a high solubility in acid and the need to use an effective retarded acid system. From the coreflood study, there is an optimum injection rate for an emulsified acid system when it was tested reservoir cores, and it was found to be in the range from 5 to 7 cm3/min. The emulsified acid system can be used effectively, with no face dissolution, at low and high injection rates. For high permeability cores, the final permeability enhancement (ratio of final to initial permeability) increased with increasing the injection rate.
Long-term cement sheath integrity is important to maintain wellbore stability and effective zonal isolation. Various factors influence cement sheath integrity, such as effective placement of cement, mechanical and thermal stresses, and interaction with corrosive gases. Corrosive gases are known to chemically attack Portland cement. However, the challenge is designing a cement system that can sustain CO2 and H2S attack.
Acid-gas-resistant systems are useful in various applications, including producers and CO2 injector wells. To understand how the cement sheath is affected by prolonged exposure to corrosive gases, detailed studies should be performed at different temperatures and pressure conditions.
This paper documents a resilient cement system that was exposed to CO2 and H2S gas environments for a period of three months. For comparison purposes, a neat cement system was used as a reference and tests were conducted at 194 (90°C) and 284°F (140°C). X-ray density profiles obtained using tomography techniques were used to analyze samples. The cement samples responded differently to CO2 and H2S environments. Formation of CaCO3 on exposure to CO2 was evident and was reflected in X-ray density profiles. Conversely, leaching of neat cement was observed on exposure to H2S gas. In both cases, the resilient cement system specially designed for the work described proved to be a better option when compared to neat cement because the destruction was less prominent in the former case.