NMR relaxation measurements are routinely used in the petroleum industry to estimate permeability and to partition fluids to estimate irreducible water saturation. The shape of the relaxation time distribution is controlled by many mechanisms like pore-coupling in the presence of heterogeneity, internal gradient effects, and signal to noise ratio. However, given an anchoring of the relaxation time distribution, the logarithmic average of the NMR T2 distribution is a relatively robust measure and for rocks where a correlation between pore and throat size exist, a reliable estimate of permeability can often be made. In this work we utilize high resolution X-ray CT images Berea and Bentheimer sandstone and simulate the NMR relaxation-diffusion responses for the case of drainage by a non-wetting fluid at different magnetic field strength (2MHz, 12 MHz, and 400 MHz), calculating internal magnetic fields explicitely. The T2-D responses are projected onto the relaxation axis for each fluid and the SDR model used to predict absolute and relative permeabilities. The resulting correlations between NMR response and relative permeability are surprisingly strong. In particular, reasonable correlations exist between lattice Boltzmann derived relative permeability and NMR estimated relative permeability even for the effective permeability of the oil. This suggests that internal fields help in establishing a surface related/weighted relaxation mechanism for the non-wetting fluid. This methodology allows testing the applicability of SDR type relative permeability estimates for the purpose of log analysis. A variety of cross-correlations including resistivity information can be considered and correlations between relative permeability and NMR response are optimized by finding the best NMR acquisition sequence and interpretation (e.g. choosing optimal cut-offs).
One of the major challenges of drilling and completion of oil and gas wells is the uncertainty in the formation fracture gradient and the fracture pressure. It is not uncommon that many drilling companies have spent money, resources and time in drilling and completing wells that should have been simply and optimally done. Fracture gradient evaluation constitutes one of the essential parameters in the pre-design stage of drilling operations, reservoir exploitations and stimulations. Several calculation methods and computer models have been presented in the literature for different regions of the world. Most of these techniques were based on either parametric or empirical correlations, which required a prior knowledge of the functional forms or the use of empirical charts which were not very accurate.
This paper presents an innovative method of predicting formation fracture gradient for Gulf of Guinea region. A combination of "Mathew and Kelly?? correlation, "Hubbert and Willis?? correlation and Ben Eaton mathematical models were used in developing the simplified technique based on field data from the Gulf of Guinea. The model compared favorably with the existing fracture gradient results in the Gulf of Guinea with less than 1 % deviation from other correlations thereby saving the rigors and time in using tables, charts and other long techniques. Although the method was developed specifically for the Gulf of Guinea, it should be reliable for other similar areas provided that the variables reflect the conditions in the specific area being considered.
Abdul Rahman, Norain (Petronas Carigali) | Mohaideen, Azlan (Petronas Carigali) | Bakar, Farah Hanim (Petronas Carigali Sdn Bhd) | Tang, Kien Hoe (Schlumberger WTA Malaysia S/B) | Maury, Radha (Schlumberger) | Cox, Paul (Schlumberger) | Le, Phi (Schlumberger) | Donald, Hugh (Smith Bits, A Schlumberger Company) | Brahmanto, Edwin (Schlumberger) | Subroto, Bramanta (Schlumberger)
In mid 2010, Petronas Carigali (PCSB) initiated a drilling campaign of a green field development at the Malay Basin, offshore Peninsular Malaysia. The operator is required to drill a borehole through a challenging interbedded formation with hard streaks calcareous to access natural gas reserves in one of the fields. In two development wells, stick-slip reached an unacceptable level increasing the risk of tool failure while driving up field development costs. The operator required an analysis methodology to ascertain the root cause of drilling dysfunction to optimize the bottom hole assembly (BHA) design and drilling parameters to mitigate vibration and improve drilling performance. To solve the problem, a finite element analysis (FEA) based modeling system was employed to analyze application details from the previous two wells and derive an improvement scheme.
Drilling dynamics data and logging information was collected along with operating parameters, mud logs and PDC bit dull grades. Additional problems were identified included hole washout, insufficient WBM lubricity and issues with a reaming stabilizer. An advanced rock-strength analysis system was used to determine unconfined compressive strength (UCS) of the interbedded formation.
Once all issues had been identified, the model was calibrated and readied for dynamic simulation. A variety of BHA configurations and PDC bits were run under different drilling conditions and operating parameters. The results of the simulations provided sufficient insight to the cause of the high levels of lateral and torsional vibration.
Using the knowledge gains, engineers selected the most appropriate PDC bit and BHA configuration. An optimum range of operating parameters with different weight on bit/revolutions per minute combinations were provided to field personnel to ensure the highest possible rate of penetration (ROP) and still remain in the established low vibration window.
The modeling effort proved successful and the third well was drilled with significantly lower torsional vibration compared to the first two wells. This paper will detail the collaboration and integrated approach of the service company in determining vibration issues and solving the problem, hence enhancing the drilling performance of upcoming wells.
Phase 1: Drilling Data Analysis
During this part of the analysis, the initial available post drilling data obtained was investigated in search for clues that might lead to the possible causes of vibration. More focus was placed on analyzing Well 2 as there were more recorded data available for this operation (Figure 1).
Tursinbayeva, Damira (Tengizchevroil) | Lindsell, Karl Michael (Tengizchevroil) | Zalan, Thomas Anthony (Tengizchevroil) | Dunger, Darrin Allen (Chevron Corporation) | Kassenov, Baurzhan (University of Tulsa) | Howery, Randy (Tengizchevroil)
Over the field life, surveillance in Tengiz oil field has provided historical and baseline data for simulation history matching, static and dynamic reservoir characterization and modeling, and the foundation for efficient well management. Hence, it continues to be an important part of everyday field operations. At the surveillance planning stage, the comprehensive opportunity list of well candidates is developed based on input provided by members of multiple teams: geologists and petrophysists, production and reservoir engineers, drilling and field operations specialists. SCADA system, permanent downhole gauges (PDHGs) and multiphase flow meters (MPFMs) are widely implemented for production data acquisition and analysis. However, the majority of surveillance activities still need well intervention into the high pressure, high H2S concentration wellbores, often during harsh weather conditions. Each job execution plan is therefore focused on the safest procedure to obtain the necessary data. Each planned survey in the surveillance plan is ranked according to the value of information to be obtained, in order to help schedule the timing of surveillance based on plant production needs.
The ultimate goal is to safely execute planned surveillance to support production optimization and field development work. This paper will highlight TCO success in addressing the different reservoir and well production uncertainties through a properly designed surveillance plan with both short and long-term objectives.
‘Safety First,' the motto of petroleum industry has been in focus since early 20th century evolving HSE considerably and as of today, we have industry best HSE practices nevertheless accidents still happen. A welder lost his life after he entered inside a 30?? pipe to inspect a weld joint. This is despite safety alert being widely circulated two weeks prior for a similar accident happened elsewhere. Are accidents inevitable or preventable?
‘Preventable,' would be the intuit answer but when prodded deeply with a psychological perspective the scenario apparently leaves an ounce of doubt, ‘was it inevitable?' To demystify the fatalistic thinking, a psychoanalyst's perspective is required to unveil the latent human factors that lead to unsafe acts. Even the safety regulations cannot rein human decision making processes which are affected by cognitive biases such as intuition, overconfidence, illusion of control, confirmation, complacence and hindsight. Under such constraints, it is no surprise that incidents reoccur whereas companies search for compliance gaps in HSE implementation.
Taking into account the case study of fatal welder accident, this papers explores human error and its influence on performance level, unveils human brain functioning, describe briefly five cognitive biases that influences unsafe acts, conjure the fatal welder accident with plausible biases, and concludes calling for more efforts to increase the awareness of cognitive biases and develop a safety culture helping to prevent incidents and improve HSE performances.
Key words: HSE, human error, performance, cognitive biases, metacognition, safety culture.
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.
Several giant carbonate reservoirs have undergone decades of waterflooding, and are now transitioning to EOR recovery processes. Simulation models that were calibrated via history matching while undergoing a waterflood (i.e.two phase flow
performance) are utilized now to predict three phase flow performance encountered with EOR processes. How reliable are these predictions? Are they accurate enough to be used for business decisions?
In this work, validity and reliability of simulation models, that has been history matched by two-phase flow processes of water flooding, to predict the performance of three-phase flow of WAG processes was assessed.
To accomplish study objective, fine grid of two 5-spot sectors model was built and then upscaled. Upscaled model was then history matched to the results obtained from the fine model using water flooding data and utilizing pseudo functions data. The
resulted cases as well as the fine model were then taken to prediction to estimate the performance of three-phase flow of gas and WAG processes. Results of fine and coarse models were then analyzed and compared to draw conclusions on the
reliability of the coarse models to match the predicted results of the reference model of the fine simulation model
Oil reservoirs are very complex systems with flow properties varying from the pore to reservoir scale. To simulate fluid flow in the reservoir, there are many uncertainties ranging from the spatial distribution of basic rock properties to the quantification
and impact of rock/fluid SCAL models of wettability and associated hysteresis. The process of history matching attempts to reasonably reproduce the past field performance by fine tuning some or all of these uncertain parameters while reasonably
maintaining their physical nature in the simulation model. It is well known that well history matched simulation models are more trustworthy in predicting future reservoir performance. Errors in these future performance predictions may be introduced,
however, when future development plan include processes that were not experienced historically.
The main purpose for using pseudo functions is to reduce the number of grid cells of reservoir models, trying to reproduce the behaviour of the fine scale system with coarser models. More specific, pseudo functions have been used historically to history
match the fine grid models into one representative upscaled model. This model (the upscaled one) should be used for further field development which employs the prediction of reservoir performance under different depletion and operating scenarios.
Most of the found literature was focused on simplifying multi-dimensional (2D) or (3D) systems to 1-dimensional (1D) models 1,2,3,4. Very limited number of grid blocks where allowed by the available computers at that time. The use of pseudo
relative permeabilities and capillary pressures was one way of decreasing grid dimensions into a more tractable level with minimal loss of simulation accuracy.
Another reason was to account for numerical dispersion that occurs through upscaling process. The upscaled relative permeabilities (pseudos) can compensate for the increase in numerical dispersion as the grid is coarsened 2,5,6.
The increasing complexity of new exploration targets requires the use of both seismic and non-seismic methods in the exploration process. This is readily achieved by integrated workstation software that enables simultaneous interpretation and modelling of both data sets. Where 2D seismic control is sparse and highly ambiguous, Gravity and Magnetic data provide additional independent measurement of the subsurface; and a more reliable integrated interpretation of complex geologic structure, adding value and reducing risk. Further, continuous improvement in data resolution and sensitivity [from land, marine and airborne acquisition and processing systems] are making completely new applications possible, expanding Potential Fields methods from regional ‘reconnaissance' tools into prospect scale and to some extent, reservoir scale, including both 3D full tensor gravity (3D-FTG) and magnetic gradiometry technology. Unfortunately, turmoil in the region has prevented their airborne survey deployment to date but this could readily change with improving political stability in Iraq-Kurdistan. Meanwhile, high quality public domain regional space mission ‘satellite derived' gravity and magnetic data provides the focus for understanding and mapping the tectonic framework: basement architecture and distribution of igneous bodies. Structural information so derived can be combined with basement depth estimation to improve understanding of basin morphology, evolution and the petroleum system. It can also prove valuable in identifying continuity between well and seismic data. This paper demonstrates the utility and integration of regional scale public domain non seismic data to assist with the local scale structural model and prospectivity assessments of some high fold zone blocks of interest in NE Iraq/Kurdistan. The Bazian (Block) anticline is used to illustrate a typical local scale feature for evaluation.
The Kurdish Regional Government (KRG) controlled parts of Iraqi Kurdistan are estimated to contain around 40 Billion barrels of oil and 60 TCF of gas (14USGS) making it the sixth largest petroleum reserve in the world. Sparce 2D Seismic control using both dynamite and vibroseis source are the primary geophysical data set for subsurface evaluation. Further, these often widely spaced data are highly variable in S/N exhibiting discontinuous reflection character and highly ambiguous subsurface geometries on the Post Stack Time Migrated (PSTM) section, particularly over rugged terrain. Thus, a valid geologic structural model is critical to the 2D seismic interpretation process. Public domain space mission-satellite derived regional topography, gravity and [to a limited extent in this case] magnetic data is used to help identify and delineate structural fabric, lineaments and basement block configuration in relation to both regional and local block prospectivity assessment in the low [foothills] and the high fold zones of Kurdistan. Often when the seismic data lacks the penetration capability or the spatial coverage, these data provide an independent data set to image the regional scale deep basement structure and fault trends critical to understanding, validating and evolving the imposed structural model. Both thin and thick skin detachment deformation are often valid models to explain crustal shortening and fold [trap] formation in the Zagros. Data integration at local scale was achived via a 2D seismic survey that was interpreted in conjunction with this work. Although some local scale ground survey data [gravity and magnetic] is available throughout the Low [foothills] Fold Zone (LFZ), no local scale data exists in the High Fold Zone (HFZ) of interest. This is thought due to difficult terrain in the HFZ. The Bazian (block) anticline illustrates local scale context/detail for the regional data in the HFZ. Figure 1 shows the two principal structural domains of interest in Kurdistan. Although this study is limited to public domain regional scale data(figure 2), high resolution local scale airborne gravity gradiometry could readily be deployed in this area but is currently restricted in terms of no-fly zones, e.g., 13US ITAR regulations. A sensitivity study to determine density contrast issues of the geologic targets is required to assure a useful data set.
Accurate determination of relative permeability hysteresis is needed for reliable prediction of WAG injection. We report two series of gas/water kr hysteresis curves obtained from corefloods under mixed-wet conditions. The first set began by water injection (imbibition: I) in the core saturated with hydrocarbon gas and immobile water. Then, the injection of gas (Drainage: D) and water continued sequentially and in total, three imbibitions and two drainages were carried out (IDIDI). In the second series, the core was initially 100% saturated with water and the experiment started with drainage (gas injection) followed by successive imbibitions (water) and drainages (DIDIDI) periods. The measured pressure drop and production data were history matched to obtain krg and krw values for each imbibition and drainage. The results show cycle-dependent hysteresis for both krg and krw curves. Therefore, the current assumption in existing hysteresis models that the drainage scanning curves follow the preceding imbibition curve is not supported by our experiments. Historic behaviour of both krg and krw is qualitatively different for these two series of experiments. This shows that unlike water-wet systems, relative permeability historic behaviour in mixed-wet system can be a function of injection scenario (saturation history). In the IDIDI series, both krg and krw decreased as the alternation between imbibition and drainage injection continued. In the DIDID series, no significant hysteresis was observed for krw, but krg in drainage cycles were higher than the corresponding values in preceding imbibition cycles. The results reveal that, none of the widely used hysteresis models (e.g., Carlson, Killough) is able to predict the observed cyclic kr hysteresis for alternating injection of gas and water. The results suggest that for mixed-wet systems it is necessary to consider irreversible hysteresis loops for both the wetting and non-wetting phases. In addition to WAG injection, the results presented in this paper and the conclusions drawn also have applications in underground hydrocarbon gas storage which usually involves cyclic pressurization (drainage) and depressurization (imbibition) on annual basis.
Low sa linity waterflooding (LSF) research has been gaining more momentum in recent years for both sandstone and carbonate reservoirs. Published laboratory data and field tests have shown an increase in oil recovery by changing injected brine salinity, especially for sandstone reservoirs. It is widely accepted that low salinity water alters the wettability of the reservoir rock from less to more water-wet conditions, oil is then released from rock surfaces and recovery is increased. The main objectives of the current study are to: test the potential of increasing oil recovery by LSF of a carbonate reservoir and to investigate the factors that control it. The impact of LSF on oil recovery was investigated by conducting coreflood and spontaneous imbibition experiments at 70 oC using core samples from a carbonate reservoir, crude oil and synthetic brine (194,450 ppm) which was mixed with distilled water in four proportions twice, 5 times, 10 times and 100 times dilution brines. Moreover, both crude oil/brine interfacial tension measurements (IFT) and ionic exchange experiments were carried out at room temperature (25 oC).
The results of the study show higher oil recovery as a result of reducing injected water salinity in both coreflood and spontaneous imbibition experiments. Coreflood experiments showed an increase in oil recovery by 3 to 5 % of OOIP, while spontaneous imbibition experiments showed an increased by 16 to 21 %. Additionally, spontaneous imbibition experiments provide direct evidence of wettability change by the LSF. The study also shows that the increase in oil recovery was obtained at much higher water salinity than the one observed in the case of sandstone rock.