Lv, Mingsheng (Al Yasat Petroleum Operations Company Ltd) | Al Suwaidi, Saeed K. (Al Yasat Petroleum Operations Company Ltd) | Ji, Yingzhang (Al Yasat Petroleum Operations Company Ltd) | Swain, Ashis Shashanka Sekhar (Al Yasat Petroleum Operations Company Ltd) | Al Shehhi, Maryam (Al Yasat Petroleum Operations Company Ltd) | Luo, Beiwei (Al Yasat Petroleum Operations Company Ltd) | Mao, Demin (Al Yasat Petroleum Operations Company Ltd) | Jia, Minqiang (Al Yasat Petroleum Operations Company Ltd) | Zi, Douhong (Al Yasat Petroleum Operations Company Ltd) | Zhu, Jin (Al Yasat Petroleum Operations Company Ltd) | Ji, Yu (Al Yasat Petroleum Operations Company Ltd)
Western Abu Dhabi locates in the west of Rub Al Khali Basin, which is an intra-shelf basin during the Late Cretaceous. The Shilaif source, Mishrif reservoir and Tuwayil seal forms one of the Upper Cretaceous important petroleum systems in the western Abu Dhabi Onshore. However, less commercial discoveries have been achieved within Mishrif Formation during the past 60 years since the large scale structures were not developed in western Abu Dhabi and the stratigraphic traps have not been attracted attention.
This study aims to investigate the exploration potential of both Mishrif structural and stratigraphic traps. It provided detailed study on Shilaif source rock, Mishrif shoal/reef reservoir and Tuwayil seal capability. Oil-source rock correlation, reservoir predication and basin modeling have been carried out for building Mishrif hydrocarbon accumulation model by integration of samplings, wire loggings and 2D&3D seismic data. Shilaif Formation is composed of laminated, organic-rich, bioclastic and argillaceous lime-mudstones and its generated hydrocarbon migrated trending to high structures. Three progradational reefs/shoals in Mishrif Formation were deposited along the platform margin, which are characterized by high porosity and permeability. Tuwayil Formation consists of 10-15ft shale interbedding with tight sandstone, acting as the cap rock of Mishrif reservoirs.
Mishrif hydrocarbon accumulation mechanism has been summarized as a model of structural background controls on hydrocarbon migration trend and shoal/reef controls on hydrocarbon accumulation. It is consequently concluded that Mishrif reefs/shoals overlapping with structural background are the favorable exploration prospects, and oil charging is controlled by heterogeneity inside a reef/shoal, the higher porosity and permeability, the higher oil saturation. Two wells have been proposed based on the hydrocarbon accumulation model, and discovered a stratigraphic reservoir with high testing production. This discovery encourages a new idea for stratigraphic traps exploration, as well as implicates the great exploration potential in western Abu Dhabi.
Summary: Abrupt and large changes in the earth properties (velocities) can cause conversion of the compressional waves to converted mode energy. Such converted waves could be recorded on the towed streamer seismic data. If they are not identified and removed early they can mislead the interpretation. In this paper, we are showing the successful application of the converted wave attenuation (CWA) workflow on the seismic data from the Mediterranean See, Offshore Egypt. Data is acquired with latest broadband technique and went through several iterations of velocity model building. The presence of the strong converted waves has threatened to undermine velocity model building and interpretation effort. The benefit of presented workflow is that it identifies and models the converted energy pre-stack pre-migration, however the subtraction is done pre-stack post-migration. Post-imaging subtraction gives improved flexibility in signal protection and improvements in the S/N ratio, especially in the areas where the separation of the converted more and compressional energy is small. Presented workflow is universally applicable to any areas where the converted modes occur.
Shiwang, Rahul (Baker Hughes, a GE company) | Chandrashekar, Telu (Oil & Natural Gas Corporation Ltd.) | Banerjee, Anirban (Baker Hughes, a GE company) | Chakraborty, Srimanta (Baker Hughes, a GE company) | Telang, Viraj (Baker Hughes, a GE company) | Deshpande, Chandrashekhar (Baker Hughes, a GE company) | Malik, Sonia (Baker Hughes, a GE company)
A number of exploratory wells were drilled in Eastern Offshore of India, encountering thick turbiditic sequences. The formation evaluation through conventional logging tools is a challenge in such depositional environments as the tools are unable to resolve thin beds and provides a weighted average log response over a collection of beds. In such environments, often the potential pay intervals are overlooked if comprehensive petrophysical analysis is not carried out. While the thin bed problem underestimates the reservoir potential, the orientation of measurement of the petrophysical properties further complicates the problem due to formation anisotropy. Another important characteristic of layered thin bed sand shale sequence is the acoustic anisotropy due to the transversely isotropic nature of sedimentary deposition.
The multicomponent induction tool was logged in the study area, providing a tensor measurement of the horizontal (Rh) and vertical (Rv) components of resistivity. The well encountered thick turbidite sequence of laminated pay sands with very low resistivity contrast. The initial stochastic petrophysical analysis from conventional open hole log responses indicated poor reservoir quality with high water saturation. Integration of high-resolution acoustic data and VTI analysis with multicomponent induction tool shows a clear evidence of alternating shale and sand sequences in the target reservoir. A high-resolution processed acoustic porosity was incorporated to build the lithology model with multicomponent resistivity data. Integration of ResH, ResV and VTI into a Thomas-Stieber petrophysical model indicates potential hydrocarbon bearing sands at two depths which were further included to optimise the formation testing and sampling plan.
During fluid sampling at the two identified depths, 54 and 157 ltrs. of fluid volume was pumped out before collecting samples by utilizing real time downhole fluid identification technologies. Optical absorbance and refractive indices were used to differentiate between miscible fluids. Clean-up from SOBM to formation oil was monitored using trends in representative channels of constantly changing absorbance spectrum. The formation testing results, therefore, were in good agreement with the identified pay intervals from the T-S model. Furthermore, Stoneley permeability analysis were carried out in the study area and calibrated with formation testing results. In the absence of imager data in the example well, formation dip was computed based on the multicomponent induction tool, which provided a close match to the OBM imagers, which struggled due to low formation resistivity, logged in adjacent wells.
This paper highlights the integrated workflow of multicomponent resistivity data based Thomas Stieber petrophysical model with high resolution acoustic and formation tester results of the example well and its success in delineation of pay sand intervals.
Alzaabi, Mohamed A. (ADNOC) | Uzun, llkay (Colorado School of Mines) | Eker, Erdinc (Colorado School of Mines, Halliburton) | Kazemi, Hossein (Colorado School of Mines) | Ozkan, Erdal (Colorado School of Mines)
As a result of shale oil and gas production success in the United States, development of shale resources elsewhere around the world has gained great interest. In the Middle East, where much of the world's conventional reserves are located, huge investments have been deployed to evaluate the potential of shale reservoirs. In this paper, we present an integrated reservoir characterization study of Shilaif shale formation in the United Arab Emirates, which includes an assessment of the primary production from a test well using a multi-phase, dual-porosity model. We also evaluated enhancing production performance via improved well completion.
In characterizing Shilaif's unconventional shale reservoir potential, we developed an integrated plan and workflow that included gathering and assessing the geological, petrophysical, and production data from a horizontal exploration well. The data used in the workflow included well-logs, cores, completion information, and pressure transient and production data from the well. The analysis of pressure build-up data ensuing the rate-transient period provided an estimate of effective formation permeability, which is a unique aspect of this study because such tests are not routinely conducted in shale reservoirs. The hydraulic fracture stimulation had improved the effective permeability nearly two orders of magnitude compared to the matrix permeability from cores and well logs. For the ultimate assessment and future performance, we developed a multi-phase dual-porosity numerical model. The simulation model was used to history-match the production data of hydraulically fractured horizontal well in Shilaif formation and case studies were conducted to evaluate the production potential.
For future development plans, it was determined that decreasing the fracture spacing from 250 feet to 150 feet was not economically feasible because the incremental production was around eight percent during the first year of production. Nonetheless, the simulation model indicated that Shilaif's large shale reservoirs may be viable for future development targets in the Middle East arena.
A major Permo-Triassic carbonate gas reservoir that was deposited on a very broad, shallow, restricted marine platform across the Arabian plate consists of interbedded carbonates and evaporites with episodes of minor windblown clastic influx. The reservoir has several characterization challenges including: heterogeneous mineralogy, rapidly varying sediment layers, constrained grain sizes (indicating very low initial energy differentiation in the sediments constituting the facies) combined with subsequent lateral reworking in the transgressive systems tract, thin parasequences, aerial exposure, lateral reworking and multiple episodes of diagenesis. During more than three decades of production, many studies have attempted to characterize this formation for the optimization of the gas production. Matching the production history and predicting the dynamic behavior of current and planned wells in this reservoir is still a difficult task. Highly variable mineralogy and pore types suggest significant vertical and lateral variations in the reservoir property parameters used to determine reservoir gas saturation and productivity. This work focuses on the integration of the detailed depositional facies model with the Pressure Depletion Petrophysical Rock Types (PDPRT) developed by Clerke and Al-Nasser to improve the reservoir performance prediction.
We use a comprehensive (~1000 feet of core covering ~220 depositional para sequences) set of cored wells and a carefully designed core analysis program to develop a database defining important links between facies and PDPRT's. Of the nine depositional facies defined by sedimentologists, five of them have reservoir potential. The results from this thorough program improves the hydrocarbon saturation calculation and the prediction of reservoir dynamics during pressure depletion. This state of the art characterization workflow includes: core description, thin section examination, petrographic analysis, mineralogy at multiple scales, routine core analysis (RCA) at multiple overburdens, mercury injection capillary pressure (MICP) measurements, porous plate data, and Archie parameter determination.
The Pressure Depletion Petrophysical Rock Types (PDPRT)-pore types for the highly variable carbonate lithology are defined using a two stage classification: first on the continuous mineral framework defined from QEMSCAN (Quantitative Evaluation of Minerals by Scanning Electron Microscopy) mineralogy images and then by the dominant pore type using quantitative petrographic data. These PDPRT's-pore types are also completely characterized by their Thomeer pore system parameters obtained from analyzed MICP data. These data define the pore throats of the rock-pore types in detail and with greater petrophysical rock type contrast than the conventional poro-perm method.
We obtain and also present here the significant links discovered between the depositional facies and our petrophysical rock-pore types. Integrating depositional (and depositionally related diagenetic) patterns with petrophysical rock typing greatly improves the reservoir dynamics prediction. Additional improvements come from the observation that early anhydrite reservoir pore cements result from the vertical juxtaposition of cycle-capping, tidal-flat facies with reservoir bodies in underlying parasequences. These links significantly improve reservoir model water saturation calculations and permeability predictions, which then leads to improved well placement, reduced CAPEX, production optimization and improved OGIP estimates.
The western area of Abu Dhabi's Late Jurassic Arab Formation is a huge ultra-sour gas reservoir with an areal gradient in composition. Early on, the data suggested a trend in H2S concentrations along the axis of the field with a sour gas entering from the southwest and migrating to the northeast. This sour gas contaminated the existing reservoir fluid and created the current areal gradient. Gas properties also varied, and in particular, dew point pressure.
This paper describes the innovative methodology used by ADNOC Sour Gas to input the varying compositions into the simulation model. The methodology consists of two major steps. In the first, PVT data was analyzed and correlations between H2S and other components were established. The second step involved using PETREL to create compositional maps.
Ultimately each grid block was assigned a unique composition based on the H2S concentration at that location resulting in a continuously varying compositional gradient. Concentrations of other components were assigned based on the H2S concentration.
The result was a dynamic model which duplicates the areal distribution in composition and accurately predicts the varying dew point pressures using a single Equation of State. Simulation predictions of condensate and sulfur production has been verified by actual plant yields. Four years of production has shown the veracity of the initialization of the composition in the model as no modifications to the original compositional distribution was required.
A novel well concept to unlock reserves from mature gas fields in Northern Germany has been developed. This concept combines cemented completions with through-tubing coiled-tubing drilling to enable significant cost reductions using ultra slim hole drilling in sour gas bearing, Upper Permian Zechstein dolomite reservoirs.
Once gas reservoirs mature, drilling of conventional infill wells can quickly become economically unattractive. Often this leaves resources untouched and it limits the economic life span of a field. To improve the economics of infill drilling in deep and mature gas fields significant cost reductions are necessary. These cost reductions can be achieved by changing the proven, yet costly, casing scheme to an ultra slim hole well concept. Besides unfavorable economics another challenge while drilling with conventional technology in mature fields can be the reduced inflow performance caused by formation damage. This challenge can be overcome by under- or at-balanced drilling, which is enabled by through-tubing coiled-tubing drilling.
Despite improved efficiencies gained from knowledge by drilling many offset wells, the estimated gas volumes are not sufficient to justify drilling of new wells with the established and conventional well design. Therefore, the operator prepared an advanced ultra slim hole well concept. The casing shoe setting depths remained unchanged, however the hole sizes are reduced significantly. The openhole reservoir section is changed from 5.875-in to 2.5-in and this section is drilled with coiled-tubing and through the installed completion. The size of the completion is selected to be 3.5-in and it is cemented in a 4.125-in hole. In this application, the cemented 3.5-in completion eliminates an entire 7-in liner that would be necessary in the conventional casing scheme. The remainder of the ultra slim hole well is drilled with a 5-in drilling liner, a 7-in intermediate casing and a 9.625-in surface casing. This needs to be compared with the conventional casing scheme comprising of an 18.625-in surface casing, a 13.375-in intermediate casing, a 9.625-in production casing and a 7-in liner. The reduction in cost is estimated to be in the order of 40%.
The presented concept can enable significant cost reductions and by applying this ultra slim hole concept further infill drilling in mature gas fields can become more economically attractive. Moreover, formation damage can be overcome by underbalanced drilling, which is enabled by drilling through-tubing with coiled-tubing. The synergies created by combining cemented completions with coiled-tubing drilling are presented in this paper.
Salahuddin, Andi A. B. (Abu Dhabi National Oil Company, Onshore) | Khan, Karem A. (Abu Dhabi National Oil Company, Onshore) | Al Ali, Reem H. M. (Abu Dhabi National Oil Company, Onshore) | Al Hammadi, Khaled E. (Abu Dhabi National Oil Company, Onshore)
This paper described the novel approach for stochastically modeling complex carbonate reservoir lithofacies and properties distribution within a High Resolution Sequence Stratigraphy (HRSS) framework. The carbonate lithofacies discussed in this paper contains heterogeneous pore types and properties. The reservoir displays an extensive range of geologic and petrophysical properties that make the efficient recovery of hydrocarbons is a challenging task. Hence one of the key steps in improving the recovery factor is by defining the three dimensional variability patterns in the reservoir in the form of fine geocellular static model. The key static geological elements that must be well defined are HRSS framework, lithofacies architecture, and field wide rock properties.
Subsurface analysis was done by examining 600 feet core footage from more than 15 wells, conventional logs from more than 50 wells, and more than 350 thin sections. The reservoir section averages 35 feet that can be subdivided into 6 high-frequency sequences. The reservoir consists of lagoonal packstone-rudstone, grain rich ooid-peloid shoal, and rudstone-boundstone mid-ramp. The shoal deposits exhibit the best permeability and oil saturation and it consists of discontinuous lithofacies body that depicts locally excellent porosity and permeability characteristics.
Lithofacies geometry and properties studies must form a fundamental basis for characterizing and modeling HRSS framework and lithofacies architecture variability through the reservoir. Combined with wireline-log data, they provide a basis for defining both reservoir framework and rock attribute distributions.
Complex lithofacies geometries and transitions, both vertically and laterally between the mound and discontinuous grain-rich ooid-peloid shoal lithofacies together with the continuous and sequential lagoonal and mid-ramp lithofacies does not allow to simulate these sorts of lithofacies assemblage using single lithofacies model algorithm. Hence a new holistic approach was implemented. A combination of Object Based (OB) algorithm and Truncated Gaussian Simulation (TGS) algorithm was employed to handle the complex lithofacies transition. This enables generating multiple realistic field wide lithofacies distribution and relationship which aligns with data trend, subsurface analog in the nearby fields, as well as that is from the outcrop exposure. The established lithofacies distribution within HRSS framework was then used to constrain field-wide properties and diagenetic trend and distribution in the reservoir.
This new holistic approach has recently been successfully implemented in the studied field. The resulted geostatistical model was able to explain pressure depletion and production rate as shown in historical production data of the field. The resulting dynamic model will hence provide reliable production forecast and reservoirs development plan which will eventually allow accomplishing the mandate recovery target.
Unconventional reservoirs, especially shale gas reservoirs, exhibit dual porosity (free fluid porosity and adsorbed fluid porosity). The adsorbed volume is a function of total organic carbon (TOC) and thus, higher organic contents are assumed to be directly related to higher hydrocarbons in place. However, this case study tried to evaluate this concept and found that with higher TOC, though gas in place increases the recoverable hydrocarbons reduces due to the low contribution from adsorbed heavier components.
We thoroughly evaluate the impact of organic contents on adsorbed hydrocarbons and further compare with the petrophysical properties and production behaviors; herein using information from the Devonian aged Duvernay Formation in Western Canada. First, multi-well analysis of core and log-derived TOC revealed that variations in organic contents are a function of the stratigraphy and thermal maturity, particularly increases in carbonate contents seems to correlate with lower organic contents, whereas increases in quartz and clays correlate with higher organic contents. Then, adsorption capacities were analyzed as a function of variations in the TOC. Finally, comparisons of hydrocarbons in-place and production contribution of the adsorbed volume is analyzed for different average TOC wells.
It is observed that TOC impacts relative adsorption of methane which further impacts the fluid characteristics (gas wells have higher average TOC as compared to the oil wells). This observation becomes relevant as we could partially understand well performance from fundamental understandings of the variations in organic contents. Results of Langmuir isotherms indicate a significant increase in adsorption of heavier components compared to the increment in adsorption of methane components with higher TOC. This observation is further analyzed for production data of the multi-fractured horizontal wells which suggested the following: 1) desorption in the oil flowing wells increases as the saturation of the oil phase decreases, or in other words when the relative permeability of the gas increases. 2) In the gas flowing wells, desorption does not follow the trend of the relative permeability, while based on Langmuir pressure initial contribution is significant which declines as reservoir pressure drops. Further, for the gas flowing well, the production forecast from calibrated production model (with measured produced volumes) shows that post-production of 10 years, recovery is 3.66% in which contribution from desorption is about 17.6%. This observation in the production analyses highlights how with different adsorption capacities of heavier components, adsorption contribution in the production varies. Finally, post this study it is found that TOC plays a vital role in adsorption capacity, gas in place and in the production performance. The relation of the TOC with fluid characterization and recoverable reserves is complex and should be analyzed with the variation in adsorption and desorption capacity of lighter and heavier components.
Rudists are a group of strange shaped marine bivalves lived in the Tethys Ocean from the Late Jurassic to the Late Cretaceous. The rudist-bearing carbonates form a lot of oil and gas reservoirs in the Middle East. Therefore, the taxonomy, morphology, paleo-ecology of rudists is important to understand the rudist-bearing carbonate reservoir features for oil exploration and development. However, it is difficult to understand these characters of rudists because we can't collect whole rudist samples from the underground oil and gas reservoirs through core sample. X-ray CT is a useful method to visualize three dimensional rudist images with non-destruction of the core. Hence, X-ray CT has a potential to obtain the information of the taxonomy, morphology and depositional environment of rudists from core information. We conducted the X-ray CT scan to the reservoir formation (Formation A) of the Cenomanian age using core slab samples of Well #A and Well #B in the Abu Dhabi oil field. The some rudist fossils were observed on the cutting surfaces of slab cores in the both wells. However, the three dimensional morphology of rudists were not identified inside of the slab core. On the CT images, some autochthonous rudists were identified and it made the colony in Well #A. This rudist is standing position and suggesting original position of depositional environment from