During drilling, openhole logs provide valuable data to identify the location of hydrocarbon resources, characterize the host formation, and quantify the asset in terms of size and producibility. Such data acquisition during field appraisal plays a critical part in the preparation of the field development plan. However, openhole logs may not be available or may not be possible due to various constraints. In some cases, data that is essential for petrophysical evaluation has been overlooked during the planning of the openhole log acquisition. In other cases, wellbore conditions while drilling may preclude openhole logging in favor of securing the well. This latter scenario can often occur in appraisal wells when knowledge of the pressure regimes in the different formations in the field is still incomplete.
Several logging services are available for acquiring formation information through casing. This capability can provide an excellent option to acquire the necessary formation evaluation data through casing, thereby completing the input to the decision-making process.
We present three separate examples in which casedhole formation evaluation was used to augment data acquired in the open hole for an improved formation evaluation. The applications range from providing reliable density and sonic data for seismic tie-in to providing more accurate estimates of porosity and saturation for selection of test intervals or for input to the static geological model. The examples demonstrate the use of various through-casing formation evaluation technologies including density, neutron, resistivity, acoustic compressional and shear slowness, and pulsed neutron capture and inelastic spectroscopy logs. We show that through a judicious combination of logs the primary evaluation objectives can be fulfilled.
We discuss the challenges in data acquisition, the steps for quality assessment of the data acquired through casing, and interpretation procedures to integrate all the data in an answer product. The substantial benefit of such an option to the operator is also discussed.
National and International Oil and Gas Companies are continually seeking and applying new technologies, processes, and methods to reduce their cost of finding and producing hydrocarbons in order to maximize Return-On-Investment (ROI), and remain competitive in the current and challenging global economy. Improving the efficiency of business processes and maximizing the productivity of the workforce is a key component for success. A key strategic component is to reduce the time it takes to develop technical staff abilities, skills and confidence to become independent contributors.
Although technology has helped companies utilize advanced measurements it remains a challenge to develop Operations and Reservoir Petrophysicists. Strategic non-conventional training that is based on technical competency management skills assessment has emerged as a fundamental tool. Frequently, traditional training that is not competency based may lack the proper vehicles for training, technology and transferring knowledge to developing subsurface professionals. In some circumstances the lack of knowledge transfer may be jeopardizing oil and gas field development efforts.
The technical complexities of Operations and Reservoir Petrophysics can only be effectively addressed through the selection, and application of appropriate technology using a multi-disciplinary approach, hands-on, custom designed attachment program and well trained competent personnel. The skill development process must be managed using competency based assessments.
Each individual develops new skills at different rates and learns differently. For strategic attachment programs to be successful in transferring skills and knowledge it is essential to systematically identify the technology gaps and design project-specific knowledge training.
An efficient and effective way to do this is to establish core competencies for different job profiles, develop skills matrices and competencies assessments, and design training or competency improvement events to address these needs. We present a recent case study where ten Emirati nationals – 3 gentlemen and 7 ladies – of a major oil operator underwent and successfully completed a one-year attachment program in Petrophysics.
Formation waters in hydrocarbon reservoirs can have complex chemical composition. In the high-salinity hydrocarbon reservoirs of the Middle East, formation waters contain, in addition to sodium and chlorine, substantial concentrations of calcium, magnesium, potassium, strontium, carbonate, sulphate and bicarbonate ions. In recent times, advances in drilling fluids chemistry have resulted in mud-filtrate composition very different from the traditional NaCl brines. Mud filtrate can include high concentration of KCl, NaBr, CaCl2 and CaBr2. The presence of the different elements impacts the response of the logging sensors to the presence of formation water and mud filtrate in the formation.
It has been customary to account for the conductivity of the different ions by converting their concentrations to equivalent NaCl salinity. While charts for such conversions have existed, their systematic use has been hampered by the lack of user-friendly software. Furthermore, while this approach might satisfactorily account for the conductivity of the brine, very large errors occur when it is used to estimate the water-response parameters for different nuclear logging sensors.
Through the use of several software algorithms, we present a workflow for the correct modeling of the log responses of complex brines. The workflow is applied to the data of a well drilled using water-base mud through a Jurassic carbonate gas-bearing formation. The use of an equivalent NaCl salinity resulted in choice of salinity values not supported by the measurements. Futhermore, not all log responses could be correctly modeled. The application of our workflow using measured mud and formation water composition yielded excellent reconstruction of measured logs, and the petrophysical outputs matched core results very well. The workflow allowed us to quantify the errors introduced when equivalent salinity was used to estimate the downhole properties and log-response parameters of the brine.
A requirement for a high resolution fluid saturation measurement in the invaded zone of an open hole to evaluate a log-inject-log micro flood led to a fresh look at the measurement specifications available from NMR. For 20 liters injected and a permeability anisotropy (kv/kh) of 0.1 the vertical extent of the flood is 8-in. NMR has a reduced sensitivity to salinity and interfacial effects, and is suitable for time-lapse comparisons because this volumetric hydrogen porosity measurement has a sharply-defined measurement volume whose geometric factor is fixed. NMR logs are presented with a vertical resolution of several feet. This relatively poor resolution is not an intrinsic feature of NMR tools, but a consequence of the logging technique which optimizes speed. A tool with a 6-in antenna should be capable of achieving a better vertical resolution than the 22-in evident on typical logs. To improve on this, CPMG sequences, sampling intervals, logging speeds and laterally stacked passes were designed to achieve a NMR resolution close to the physical antenna length. The azimuth of each pass was recorded and only included in the stack if the azimuth was within a specific tolerance. Test runs of this tool when logged with this procedure were statistically evaluated to confirm the measurement specifications. The result is a porosity log with 8-in vertical resolution, 0.8 porosity units noise on total porosity, and with certain medium to heavy oils the possibility of determining fluid saturations to within 5 saturation units. Examples of NMR logs acquired with this new operating procedure are compared with high resolution dielectric logs. These include the evaluation of heavy oil in a thinly laminated clastic sequence from the comparison of the total NMR porosity with high resolution density porosity. This density magnetic resonance interpretation technique characterized the heavy oil in formation layers as thin as 8-in.
Serry, Amr Mohamed (Abu Dhabi Marine Operating Co.) | Tan, Willy (Schlumberger) | Ramamoorthy, Raghu (Schlumberger) | Budebes, Sultan (Abu Dhabi Marine Operating Co.) | Al-Marzouqi, Mariam (Abu Dhabi Marine Operating Co.) | Hashimura, Tadashi (Abu Dhabi Marine Operating Co.) | Desport, Olivier (Schlumberger Middle East SA.)
Proper petrophysical evaluation of carbonate formations, offshore Abu Dhabi is a difficult process considering the number of challenges to resolve. Lithology mainly consists of a combination of dolomite and calcite but also contains anhydrite which must be accounted for to get an accurate porosity. Resistivity measurements are affected by invasion and by the very high shoulder bed resistivity so computing formation resistivity can only be done through resistivity modeling and inversion, and once formation porosity and resistivity are properly computed, it is possible to compute an accurate formation saturation only if the Archie parameters cementation and saturation exponents m and n are properly defined. We will show how to resolve these challenges by acquiring and integrating in an advanced workflow a modern suite of logs including density-neutron-resistivity-gamma ray along with a multi-frequency dielectric measurement. We will also show how to confirm the formation saturation in selected zone in an Archie independent manner by combining the dielectric log and pump-out formation tester. The integration of the log data with core analysis results in a very comprehensive petrophysical evaluation of the formations encountered.
Abdel Aal, Atef Farouk (ADCO Producing Co. Inc.) | Al Daghar, Khadija Ahmed (ADCO) | Ramamoorthy, Raghu (Schlumberger) | Brahmakulam, Jacob (Schlumberger) | Hall, Jonathan C. (Scott Pickford Ltd.) | Baguenane, Boussad (Abu Dhabi Co. Onshore Oil Opn.) | Al-Marzouqi, Mohamed Bin Khalfan (Abu Dhabi Co. Onshore Oil Opn.) | Faivre, Ollivier (Schlumberger)
Knowledge of rock texture and wettability are vital for the static and dynamic description of carbonate reservoirs. Conventional log measurements are limited in their applicability for the quantitative assessment of these attributes. Rapid variations of texture in carbonates diminishes the usefulness of core measurements on samples of limited size. Obtaining representative relative permeability by restoring core to native reservoir conditions, especially the original wettability state, is also very challenging.
The dielectric response of clean carbonate rocks exhibit characteristic frequency dispersion patterns which depend on their texture and wettability. Dielectric measurements with multiple frequencies have become available enabling us to extract this information by inverting the tool data using a dispersive petrophysical model.
The dielectric response is primarily sensitive to water, and provides a measure of the water phase tortuosity, which is a combination of texture and wettability, captured in the Archie's exponents m and n. Previous work has demonstrated the estimation of m from pore size distribution obtained from NMR data using an effective medium model. Formation Resistivity Factor data from core is presented to validate the model-derived m. In this work we propose a way to combine the cementation exponent so derived with the textural answers from the dielectric measurement to make a wettability estimate. We also assess the wettability from 3D NMR stations, using the increase in relaxation of oil manifested as shortening of the oil T2 signal due to partial wetting of the oil phase.
The methods are illustrated on a dataset from a Cretaceous carbonate, onshore Abu Dhabi. The interval surveyed in the subject well straddles an oil/water contact (OWC). The n exponent value derived by the method shows that the rock above the OWC is oil-wet in varying degrees. The inference on wettability state from the NMR data further supports the conclusions.
Logging measurements in the borehole are vital for monitoring carbon dioxide (CO2) floods--for assessing the fluid changes in the reservoir rock as well as in the wellbore. The saturation profile at each well location provides the efficiency of the flood process for fluid displacement within the pore and the vertical sweep across and within the reservoir zones. A snapshot from multiple well locations in the reservoir enables the creation of a picture of the flood flow pattern, and the time-lapse surveys track the progress of the flood with time. Pulsed-neutron logs provide essential measurements for the evaluation of saturation in the injectors, producers, and observers. However, the CO2 environment, with the fluid in the borehole, remains uncharacterized in the industry. Hence, reliable inferences require either that the measurement is immune to the borehole environment or that the perturbation is minimal and can be easily corrected. Where corrections are required, suitable benchmarks should be planned in advance to verify the accuracy of the corrections. These corrections should be modeled after the physics of the measurement to the maximum extent possible. On the first CO2 enhanced-oil-recovery (EOR) pilot project in the Middle East--unique in the world because the CO2 flood was implemented with the reservoir at original oil saturation--several pulsed-neutron surveys were recorded in the injector, observer, and producer wells. The surveys included capture and inelastic mode acquisition. Several novel techniques of data acquisition and interpretation were successfully tried. This paper presents the steps in planning and executing the jobs and the results of the surveys. Limitations of existing characterization and those imposed by the measurement environments in the subject wells are discussed, and we show, through comparison with benchmarks, that correction for the unusual borehole environment is possible. The paper illustrates how the different modes of pulsed-neutron data acquisition complement each other in the individual wells in assessing the borehole environment, providing adequate input data to enable a multiphase reservoir-fluid analysis, and yielding independent fluid saturations for effective comparison. The results of the analysis are compared with openhole evaluation to help create a coherent picture of the reservoir. The fluid analysis from the pilot wells confirms the high displacement efficiency of CO2 as an EOR fluid. The saturation profiles from individual wells portray the vertical sweep of the flood, and the snapshot from the multiple wells gives the areal sweep. Combined with the data from production-log sensors and permeability from the magnetic resonance, the flood-breakthrough layers are identified.
Screening and piloting of enhanced oil recovery (EOR) methods is often a lengthy process requiring large financial commitments. The reservoir uncertainty and, for some EOR methods, the lack of fundamental recovery mechanism understanding, call for a careful and staged screening and piloting program before committing to full-field implementation. The MicroPilot* single-well in situ EOR evaluation is a new piloting technique which allows for rapid and cost effective testing of EOR methods under in-situ downhole conditions. It is a log-inject-log technique conducted with a wireline formation tester, where a small quantity of EOR fluid is injected and the resulting change in oil saturation then determined based on a set of openhole logs that are run both before and after the injection.
The MicroPilot is a proven piloting technology for alkaline-surfactant-polymer (ASP) EOR. In this paper, we investigate the feasibility of extending this new technology for testing of CO2 EOR. We demonstrate through detailed analytical and numerical modeling that the changes in oil saturation and composition expected during the CO2 EOR process are measurable by the openhole logs when taking into account logging tool resolution. Based on a test library consisting of 13 different oils, which have been carefully characterized to match experimental PVT data, and all of which are likely candidate oils for miscible CO2 EOR, we investigate the expected pilot response when injecting CO2 both above and below the minimum miscibility pressure. We further study the sensitivity of the pilot response to gravity effects as well as residual oil saturation to the CO2 flood.