Joshi, Girija (Kuwait Oil Company) | Acharya, Mihira Narayan (Kuwait Oil Company) | Al-Azmi, Mejbel Saad (Kuwait Oil Company) | Dashti, Qasem M (Kuwait Oil Company) | Van Steene, Marie (Schlumberger Oilfield Eastern Limited) | Chakravorty, Sandeep (Schlumberger Oilfield Eastern Limited) | Darous, Christophe (Schlumberger Oilfield Eastern Limited)
The deep organic-rich calcareous Kerogen of North Kuwait, a continuous 50ft thinly alternating carbonate - organic-rich argillaceous sequence, is not only a source rock but has gained importance as potential reservoirs themselves of typical unconventional category. Kerogen characterization relies on quantifying total organic carbon (TOC) and estimating accurate mineralogy. This paper describes an attempt to directly measure TOC of the Limestone-Kerogen sequence.
For the present study, empirical estimations of TOC have been carried out based on various conventional log measurements and also nuclear magnetic resonance. The introduction of a new neutron-induced capture and inelastic gamma ray spectroscopy tool using a very high-resolution scintillator and a new type of pulsed neutron generator for the deep unconventional kerogen resources have provided a unique opportunity to measure a stand-alone quantitative TOC value using a combination of capture and inelastic gamma ray spectra. In this process, Inorganic Carbon Content (ICC) is estimated by using elemental concentrations measured by this logging tool in addition to measuring Total Carbon (TC). The difference between TC and ICC gives direct TOC.
The advanced elemental spectroscopy tool measurements were first used to determine accurately the complex mineralogy of the layered carbonate and organic-rich shale sequence. The petrophysical evaluation and heterogeneity seen on borehole image logs were calibrated with extensive laboratory measurements of core / cuttings data. The final results are considerably improved compared to conventional empirical estimation. Once the mineralogy is properly determined, the log-derived TOC matches very well with core measured TOC.
This technique has provided a new direct and accurate log-derived TOC for Kerogen characterization. The application has a potential to be used for CAPEX optimization of the coring in future wells. This technique can also be applied in HPHT and High-angle horizontal wells, which can overcome challenging coring difficulties in horizontal wells.
Marie Van Steene, SPE, and Mario Ardila, SPE, Schlumberger; Richard Nelson, SPE, and Amr Fekry, SPE, BP Egypt; and Adel Farghaly, SPE, RWE Dea Summary In hydrocarbon reservoirs, fluid types can often vary from dry gas to volatile oil in the same column. Because of varying and unknown invasion patterns and inexact clay-volume estimations, fluid-types differentiation on the basis of conventional logs is not always conclusive. A case study is presented by use of advanced nuclear-magnetic-resonance (NMR) techniques in conjunction with advanced downhole-fluid-analysis (DFA) measurements and focused sampling from wireline formation testers (WFTs) to accurately assess the hydrocarbon-type variations. The saturation-profiling data from an NMR diffusion-based tool provides fluid-typing information in a continuous depth log. This approach can be limited by invasion. On the other hand, formation testers allow taking in-situ measurements of the virgin fluids beyond the invaded zone, but at discrete depths only. Thus, the two measurements ideally complement each other. In this case study, NMR saturation profiling was acquired over a series of channelized reservoirs. There is a transition from a water zone to an oil zone, and then to a rich-gas reservoir, indicated by both the DFA and the NMR measurements. Above the rich gas, is a dry-gas interval that is conclusively in a separate compartment. Diffusion-based NMR identifies the fluid type in a series of thin reservoirs above this main section, in which no samples were taken. NMR and DFA both detect compositional gradients, invisible to conventional logs. The work presented in this paper demonstrates how the integration of measurements from various tools can lead to a better understanding of fluid types and distribution.
Van Steene, Marie (Schlumberger) | Povstyanova, Magdalena (Schlumberger) | Semary, Mahmoud Gamal (Schlumberger) | Mathur, Anil Kumar (Schlumberger) | Ali, Aziza (Schlumberger) | Edelman, Jeffery Mark (TransGlobe Energy Corp) | Maghrabia, Karim Mohamed (PetroDara)
The Nukhul reservoirs of Egypt's Eastern Desert typically have low porosity, low permeability, and relatively heavy oil. Hence, hydraulic fracturing is key to enhancing reservoir producibility, and an understanding of fracture geometry is important to determine reservoir drainage.
To measure hydraulic fracture height at the wellbore, shear wave anisotropy data were acquired in casing with an advanced acoustic tool. Hydraulic fracturing post-job pressure matching also provided estimates of fracture geometry. Shear wave anisotropy data confirmed that the Thebes and Rudeis formations acted as fracture barriers and confirmed the fracture confinement in the Nukhul formation, which was the fracturing job objective.
Although, overall, the post-fracturing shear wave anisotropy measurement and the post-job pressure matching delivered similar results for fracture height at the borehole, the shear wave anisotropy data showed uneven levels of anisotropy acrossthe fractured reservoir interval, indicating that the fracture might not have as simple a geometrical shape as was modeled by the post-fracturing analysis.
Based on wireline data, a newly constructed and calibrated mechanical earth model obtained detailed rock elastic properties and stress profiles. These geomechanical properties defined 26 zones across the reservoir (instead of the initial 6) and were input into the fracturing modeling software.
Fracture geometry obtained through this enhanced modeling closely matched the shear wave anisotropy results—the modeled fracture width corresponded to the variations of shear wave anisotropy observed across the fracture height. The
fracture was narrower in the upper part of the reservoir and wider in the lower part, with a half-length of 300 ft in the lower part and almost 400 ft in the upper part.
In this case study, we demonstrate how full use of available data, application of the latest acoustic technology, and integration of multiple disciplines (acoustics, geomechanics, stimulation) can lead to better fracture geometry description and
achievement of greater accuracy in reservoir description.
An oil well with two perforated zones had an initial production rate of ~2,400 BOPD with water traces. Within 3 months, production decreased to ~1,000 BOPD and water cut increased to >25%. It was critical to identify the cause of decreasing productivity and increasing water cut to plan for remedial action.
The reservoir was evaluated by integrating several answers obtained from reservoir saturation characterization through use of pulsed neutron capture and water-flow log data, as well as from conventional and advanced production logging.
Production logging showed that water was sourced from the lower perforated interval, while only a small proportion of the flow came from the upper reservoir layer. Pulsed neutron logging confirmed a high amount of depletion in the zone below the lower perforation, with oil remaining in the upper part of the lower perforated zone and in the upper perforated zone. Bypassed oil was also found below the water-producing zone, confined between the oil/water contact and a thin shale break. This shale break is a major permeability barrier and allows lateral water movement through the high-permeability lower zone.
A multilayer test carried out with production logging tools showed that the productivity index of the upper zone was only one-tenth that in the lower zone, due to either intrinsically low permeability or high skin factor. The multilayer testing also showed that of the two comingled layers, the upper layer had approximately one hundredth the permeability of the lower layer. Reperforation of the upper zone resulted in only minor improvement in well production, thus confirming that the low productivity was not caused by high skin factor, but was due to low permeability.
From the testing, it is clear that to produce the oil from the upper zone, it will be necessary to produce the two zones separately, with different drawdown. Since similar conclusions were obtained in other wells in the field, these results provide a fieldwide strategy for improving field productivity.
Van Steene, Marie (Schlumberger Logelco Inc) | Vallega, Valentina (Schlumberger) | Shaaban, Sahar (Schlumberger Logelco Inc) | Ghadiry, Sherif Kamal (Schlumberger) | Haddad, Elie (Schlumberger) | Bassim, Essam Abdul Elaziz (Arabian Oil Company, Ltd.)
Van Steene, Marie (Schlumberger Logelco Inc.) | Povstyanova, Magdalena (Schlumberger) | Al-Attar, Haitham (BP-GUPCO) | Abu El Gheit, Diaa (BP-GUPCO) | Abutaleb, Moamen (BP-GUPCO) | Lantz, Jim (BP-GUPCO) | Abdel Kareem, Salah (GUPCO)
Multiple wellbore stability projects in the Western Desert of Egypt identified a strong sensitivity of the breakout gradient to wellbore inclination and a weak sensitivity to wellbore azimuth, from the Abu Roash to the Alam El Bueib formations. The breakdown gradient shows strong sensitivity to both wellbore inclination and wellbore azimuth. Tensile failures are a problem only in high deviation wells (deviation more than 55-60) where the breakdown gradient will in general be lower. For highly deviated wells, the occurrence of tensile failure can be reduced by drilling close to the minimum horizontal stress direction.
Breakout can be tolerated to some extent, so planning the drilling mud weight to completely eliminate it is not necessary. The extent to which breakout can be tolerated depends on the well deviation, as cuttings become more difficult to evacuate as the well deviation increases.
As losses are very common in most of the Western Desert formations, the optimum drilling mud weight should be formulated as a balance between the risks caused by breakout and mud loss.
Understanding the main causes of rock failure and applying the recommended failure mitigation measures resulted in successfully drilling four deviated wells in the area.
Computing clay volume using elemental neutron capture spectroscopy logs in combination with a multimineral solver for the complex, shaly sand reservoirs of the Nile Delta reservoir improved accuracy over using the mineral fractions output from the spectroscopy model alone. It was also found that the aluminium log from direct aluminium yield measurement leads to a better clay volume estimation, as opposed to using the aluminium log from the aluminium emulator algorithm.
Combining the spectroscopy data with borehole image data generated a high-resolution lithofacies column that provides an accurate stratigraphic interpretation. Applying cutoffs to generate a high-resolution sand count enabled us to sort the reservoir units from the poorest to the best quality sands and improved our understanding of the distribution of the best reservoir quality in the well. This approach provides a unique solution to characterize thinly bedded reservoirs in wells drilled with oil-based mud.
Women on the Frontline - An examination of work/life balance issues by women in the industry.
An increasing number of deviated wells are being drilled to maximize production and hydrocarbon recovery in the mature reservoirs of the Gulf of Suez (GoS). Successfully drilling a high-angle well in a tectonically disturbed and structurally complex area like the GoS is very challenging, especially in depleted reservoirs. Selecting the optimal mud weight is absolutely essential. Stress orientation and magnitude also have a major impact on wellbore stability.
The region poses significant drilling challenges that vary widely from reactive shale and salt creep to stress-related instability. From the findings of multiple wellbore stability projects we conducted in the GoS, we review the dominant mechanisms of wellbore instability in the GoS. We provide a summary of the failure mitigation measures and an overview of stress magnitude and orientation in the region, demonstrating how it impacts the knowledge of the most stable drilling direction.
Understanding the main causes of rock failure in the GoS resulted in improved drilling efficiency and reduced drilling costs. We show an example, where a new, nearly horizontal (86º) well was successfully drilled through the Asl formation with less than half a day of non productive time during the entire drilling process.
We conclude that acquisition of new, high-quality data would considerably reduce the uncertainty surrounding drilling complex wells in the area and reduce their cost.