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.
This paper presents a novel implementation for evolutionary algorithms in oil and gas reservoirs history matching problems. The reservoir history is divided into time segments. In each time segment, a penalty function is constructed that quantifies the mismatch between the measurements and the simulated measurements, using only the measurements available up to the current time segment. An evolutionary optimization algorithm is used, in each time segment, to search for the optimal reservoir permeability and porosity parameters. The penalty function varies between segments; yet the optimal reservoir characterization is common among all the constructed penalty functions. A population of the reservoir characterizations evolves among subsequent time segments through minimizing different penalty functions. The advantage of this implementation is two fold. First, the computational cost of the history matching process is significantly reduced. Second, problem constraints can be included in the penalty function to produce more realistic solutions. The proposed concept of dynamic penalty function is applicable to any evolutionary algorithm. In this paper, the implementation is carried out using genetic algorithms. Two case studies are presented in this paper: a synthetic case study and the PUNQ-S3 field case study. A computational cost analysis that demonstrates the computational advantage of the proposed method is presented.
Mendoza, Alberto X. (ExxonMobil Neftegas) | Gaillot, Philippe (ExxonMobil Exploration Company) | Yin, Hezhu (ExxonMobil Abu Dhabi Offshore Petroleum Company) | Nicosia, Wayne (ExxonMobil Upstream Research Company) | Guo, Pingjun (Exxon Mobil Corporation) | Mardon, Duncan (ExxonMobil Upstream Research Company) | Passey, Quinn R. (ExxonMobil Upstream Research Co.) | Wertanen, Scott R. (ExxonMobil Exploration & Production Surumana) | Zhou, JinJuan (ExxonMobil Upstream Research Company) | Fitz, Dale Edward (ExxonMobil Upstream Research Co.)
Over last several years, the ability to perform accurate, quantitative formation evaluation in high-angle and horizontal (HA/HZ) wells has been increasingly recognized as a high priority, unsatisfied need within the formation evaluation (FE) community. The industry has realized that the ability to drill extended reach wells has surpassed the ability to evaluate them. Well logs are often underutilized for geologic modeling and assessment applications due to lack of confidence in petrophysical analysis results.
In this paper, we introduce a state-of-art formation evaluation toolkit specifically developed for quantitative interpretation of high angle and horizontal well logs. Starting with wellbore images and standard triple-combo field logs, the workflow consists of: 1) three-dimensional (3D) and two-dimensional (2D) display modules for well path, wellbore images logs, scalar logs and dips to quality control (QC) the data; 2) a comprehensive image analysis module combined with log analysis to build a 3D geometrical earth model; 3) a depth coherence processing (DCP) module to effectively correct recorded borehole images of different logging tool sensors with different depths of investigation (DOI) back to borehole size (BS); 4) a 3D joint inversion module to accurately model and interpret gamma ray (GR), neutron, density, and resistivity logs, to build a common petrophysical earth model; and 5) an output module in which the common earth model is populated with bedding geometries and petrophysical property distributions.
The advanced formation evaluation toolkit described in this paper enables geoscientists to realize much more value than ever before from high-angle and horizontal well data, especially in thinly bedded reservoirs. The detailed description of the internal architecture and lateral petrophysical characterization of the reservoirs are essential for understanding stratigraphy and conditioning geological models. The improved estimations of the petrophysical properties yield more accurate estimates of reserves in place.
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.
Arnaout, Arghad (TDE Thonhauser Data Engineering GmbH) | Thonhauser, Gerhard (Montanuniversitat Leoben) | Esmael, Bilal (Montanuniversitat Leoben) | Fruhwirth, Rudolf Konrad (TDE Thonhauser Data Engineering GmbH)
Detection of oilwell drilling operations is an important step for drilling process optimization. If drilling operations are classified accurately, detailed performance reports not only on drilling crews but also on drilling rigs can be produced. Using such reports, the management can evaluate the drilling work more precisely from performance point of view.
Mud-logging systems of modern drilling rigs provide numerous sensors data. Those sensors measurements are considered as indicators to monitor different states of drilling process. Usually real-time measurements of the following sensors data are available as surface measurements: hookload, block position, flow rates, pump pressure, borehole and bit depth, RPM, torque, rate of penetration and weight on bit.
In this work, collected sensors measurements from mud-logging systems are used to detect different drilling operations. Detailed data analysis shows that the surface sensors measurements can be considered as a main source of information about drilling operations. For this purpose, a mathematical model based on polynomials approximation is constructed to interpolate sensors data measurements.
Discrete polynomial moments are used as a tool to extract specific features (moments) from drilling sensors data. Then we use these moments for each drilling operation as pattern descriptor to classify similar operations in drilling time series. The extracted polynomial moments describe trends of sensors data and behavior of rig's sub-systems (Rotation System, Circulation System, and Hoisting System). Furthermore, this paper suggests a method on how to build patterns base and how to recognize and classify drilling operations once sensors data received from mud-logging system. Drilling experts compare the results to manually classified operations and the results show high accuracy.
Extensive airborne electromagnetic (EM) ice thickness surveys have beenperformed in April 2009, 2011, and 2012 over the Canadian Beaufort Sea with along-range airplane. These are contributing to the Beaufort RegionalEnvironmental Assessment (BREA) project which gathers ice information inpreparation of a regulatory framework for safe and environmental responsibleoil and gas production. Results show that the location of the multiyear iceedge can be very variable from year to year. Multiyear ice modal thicknessesranged between 3.0 and 3.7 m. The seasonal ice zone had very variable icethicknesses depending on the amount and age of ice formed in coastal polynyasand leads throughout the winter. However, we gathered enough data to show thatmodal first-year ice thicknesses of 2.0 to 2.2 m emerge if profiles are longenough, which can be considered the most representative first-year icethickness estimate in the Canadian Beaufort Sea in April. However, in theseasonal ice zone also regions with heavily deformed ice thicker than 10 m, andoccasional multiyear hummock fields of similar thicknesses occur. Resultssuggest that multiyear hummock fields may not comprise the thickest ice as theyare affected by melt during the summer. Two ice islands had thicknesses between20 and 30 m. Our results suggest a melt rate of ice islands of 10 m per year inthe Southern Beaufort Sea. Ice thickness surveys were complemented by theanalysis of satellite radar data and tracking of ice features by means of GPSbeacons. We demonstrate that all these activities combined comprise a powerfultool for a future Arctic sea ice environmental observatory.
In August 2010 a 265 km2 ice island calved from the Petermann Glacier innorthern Greenland. Soon after the initial calving event the mass broke intoseveral pieces, some of which exited Baffin Bay and drifted south toward theLabrador coast. By June 2011 PII-A, a large fragment of the initial PetermannIce Island, was situated offshore Labrador and in one week it had moved 225 kmdown the coast. Concern arose that if PII-A continued its trajectory it couldreach the Grand Banks by August 2011, posing a potential risk for existinginfrastructure in the offshore region of Newfoundland. To properly assess thepotential risk a realistic estimate of ice mass was necessary. This in turnrequired field measurements of the ice islands thickness.
A three-day field program was carried out on the Petermann Ice Islands,PII-A and PII-A-a, from June 17-19, 2011. At this time PII-A and PII-A-a weresituated offshore Labrador, Canada, approximately 100 km northeast of the townof Rigolet. Geophysical survey methods, including Ground Penetrating Radar(GPR) and Seismic Reflection, were used to identify the base of the islands andobtain ice thickness measurements at various locations. Eight satellitetracking beacons were deployed on PII-A and one was deployed on PII-A-a.Ablation data, photographs and video footage were also obtained during theprogram. On July 22, 2011, PII-A was revisited while it was situated off thesouthern Labrador coast. GPR measurements were acquired at the pre-existingstations; the measurements allowed for deterioration rates due to surface andbasal melting to be calculated for PII-A. Results of the field measurementsindicate that ice thickness varied between 50 to 80 m on PII-A; the thicknessof PII-A-a was 30 m at a single survey location. Surface melt rates of 2.7-6.3cm day-1 were observed over a 1-day period in June. For the 35-day periodbetween June and July visits, average surface and basal melt of 5.0 cm day-1and 3.4 cm day-1, respectively, were calculated.
The hunt for further oil and gas recovery from old wells isbooming, and the industry look to new and improved technology for addingseveral years of operational time to exicting wells. New methods like lightwell intervention procedures sets high stress on old wellheads andinfrastructure, and a general increase in development of marginal fields haveraised issues over safety aspects.
Aside from developing improved procedures around cementingoperations, leakage detection and oil spill recovery, additional successfactors will be the ability to monitor pressure and temperature fluctuations inB annulus, as well as finding models and produce technology to manage suchpressure build upsuccessfully.
This paper introduces a new method of B-annulus monitoring using ultrasoundsignals originating from a device in the A-annulus providing measurements basedon time of flight in chambers placed in the B-annulus as a means of determiningthe temperature and pressure in the B-annulus.
There are large oil and gas resources in the shear zone region of theBeaufort Sea. Development of these resources would entail many factorsfor consideration. One of the most important is the ice load on drillingand production platforms. However, there is very large uncertainty on theice loads in this region due to a clear lack of knowledge of the pack icedriving forces. This pack ice driving force is one of the primarymechanisms that dictate how much force the ice can exert on an offshoreplatform, even if large multi-year ice floes are present. Improvedknowledge of this force would significantly reduce uncertainty in the designice loads, provide essential baseline engineering knowledge and a more reliablestructure, leading to greater regulatory certainty and safer and moreeconomical offshore operations.
The pack ice driving force, as a function of width, can be calculatedthrough an equation in the ISO Arctic Offshore Structures Standard. However, a relevant parameter is still poorly defined for this equationand spans a large range. As a result, calculations of driving forces arevery uncertain, yet it is the key limiting force mechanism for the BeaufortSea. This paper presents the results of a study that investigated meansof refining uncertainty when calculating pack ice driving forces. Anoverview of the standard method of determining these forces is given, as wellas a discussion of the historical development of, and implications ofuncertainty in, calculating the pack ice force. Methods for refining theuncertainty are presented and comparisons are discussed. Numericalmodelling studies offer the greatest potential for refining the uncertaintybased on cost, usefulness, confidence in the results and studyopportunities. The information provided in this paper has applicationsfor refinement of pack ice driving force calculations in current engineeringstandards. A clear understanding of the magnitude of pack ice drivingforces would help to reduce the risk of failure of engineering structures andimprove their safety, by enabling a significantly better definition of theanticipated ice loads and the upper limit of the loads for the BeaufortSea.
Poedjono, Benny (Schlumberger) | Beck, Nathan (Schlumberger) | Buchanan, Andrew (Eni Petroleum Co.) | Brink, Jason (Eni Petroleum Co.) | Longo, Joseph (Eni Petroleum Co.) | Finn, Carol A. (U.S. Geological Survey) | Worthington, E. William (U.S. Geological Survey)
Geomagnetic referencing is becoming an increasingly attractive alternativeto north-seeking gyroscopic surveys to achieve the precise wellbore positioningessential for success in today's complex drilling programs. However, thegreater magnitude of variations in the geomagnetic environment at higherlatitudes makes the application of geomagnetic referencing in those areas morechallenging.
Precise, real-time data on those variations from relatively nearby magneticobservatories can be crucial to achieving the required accuracy, butconstructing and operating an observatory in these often harsh environmentsposes a number of significant challenges. Operational since March 2010, theDeadhorse Magnetic Observatory (DED), located in Deadhorse, Alaska, was createdthrough collaboration between the United States Geological Survey (USGS) and aleading oilfield services supply company. DED was designed to produce real-timegeomagnetic data at the required level of accuracy, and to do so reliably underthe extreme temperatures and harsh weather conditions often experienced in thearea.
The observatory will serve a number of key scientific communities as well asthe oilfield drilling industry, and has already played a vital role in thesuccess of several commercial ventures in the area, providing essential,accurate data while offering significant cost and time savings, compared withtraditional surveying techniques.