Reservoir Units Research Articles

Petrophysical Properties and Well Log Interpretations of Tertiary Reservoir in Khabaz Oil Field / Northern Iraq

The aim of this study is interpretation well logs to determine Petrophysical properties of tertiary reservoir in Khabaz oil field using IP software (V.3.5). The study consisted of seven wells which distributed in Khabaz oilfield. Tertiary reservoir composed from mainly several reservoir units. These units are : Jeribe, Unit (A), Unit (A'), Unit (B), Unit (BE), Unit (E),the Unit (B) considers best reservoir unit because it has good Petrophysical properties (low water saturation and high porous media ) with high existence of hydrocarbon in this unit. Several well logging tools such as Neutron, Density, and Sonic log were used to identify total porosity, secondary porosity, and effective porosity in tertiary reservoir. For Lithological identification for tertiary reservoir units using (NPHI-RHOB) cross plot composed of dolomitic-limestone and mineralogical identification using (M/N) cross plot consist of calcite and dolomite. Shale content was estimated less than (8%) for all wells in Khabaz field. CPI results were applied for all wells in Khabaz field which be clarified movable oil concentration in specific units are: Unit (B), Unit (A') , small interval of Jeribe formation , and upper part of Unit (EB).

Research on Well-seismic Characterization of Multi-layer Sandstone Reservoir

Multi-layer sandstone reservoirs are one of the important types of A dilute oil reservoirs. They have reached the middle and later stages of development, with the following characteristics: controlled by multiple multi-level faults, many faults, small fault blocks, small fault block reservoir area; affected by sedimentation, the distribution of sand bodies is discontinuous and the connectivity is poor, resulting in serious reservoir heterogeneity; after long-term water injection scouring, the reservoir properties and oil-water properties have changed, and the remaining oil distribution is complicated. These characteristics determine that the research focus of this type of reservoir is to carry out fine characterization of reservoir well-seismic joints, establish the isochronous stratigraphic framework of the reservoir unit, analyze the characteristics of small faults and microstructures in the reservoir, and describe various sand bodies between wells. The internal heterogeneity and the three-dimensional spatial distribution regularity of the oilfield are used to establish a fine three-dimensional reservoir geological model, which provides strong technical support for revealing the spatial distribution characteristics and laws of the remaining oil.

Overcoming Challenges in Chemical EOR During Polymer Breakthrough

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 194689, “Challenges in Selection and Use of Production Chemicals With Chemical EOR Operations During Polymer Breakthrough Phase,” by Robert Zagitov, Panneer Selvam Venkat, and Ravindranthan Kothandan, Cairn Oil and Gas, et al., prepared for the 2019 SPE Oil and Gas India Conference and Exhibition, Mumbai, 9-11 April. The paper has not been peer reviewed. In chemical enhanced oil recovery (EOR), challenges are expected regarding production chemistry and production-facilities operations. Partially hydrolyzed polyacrylamide (HPAM) is used widely for controlling mobility ratios. Complex in water chemistry and rich in positively charged divalent ions, flooded polymer, having a negative charge, interacts with divalent ions of produced water (PW). The complete paper discusses the importance of adequate preparation and the approaches used to overcome challenges of EOR operations, including handling back-produced polymer. Introduction The Mangala field in northwest India, discovered in January 2004, is part of the Barmer Basin. The primary reservoir unit in this field is the Fatehgarh group, a high-quality quartzose sandstone reservoir having high net-to-gross ratio, high porosity (21-28%), and multidarcy permeability (200 millidarcy to 20 darcy) with an average permeability of approximately 5 darcy. The reservoir contains waxy crude with gravity ranging from 20 to 28 °API. A primary recovery efficiency of less than 10% stock-tank oil initially in place is estimated on the basis of simple depletion; thus, the base field-development plan envisaged implementation of waterflooding from the start of production to maintain reservoir pressure and sweep reserves. Detailed laboratory studies have established that aqueous-based chemical EOR processes are best suited for these viscous oil fields. Full-field polymer flooding has been implemented in the Mangala field, with an injection at the time of writing of nearly 400,000 B/D of polymerized injection water (IW) with average polymer concentration of approximately 2,500 ppm. HPAM is mixed with source water to create a mother solution of 15,000-ppm concentration at a central polymer facility and is distributed through a pipeline network to 15 well pads, where it is diluted with IW to achieve a viscosity of approximately 30 cp for injection. Artificial lift is achieved either by jet pump or electrical submersible pump. Average water cut is 80% at the time of writing.

Novel Method for Inverted Five-Spot Reservoir Simulation at High Water-Cut Stage Based on Time-Varying Relative Permeability Curves.

After large-scale and long-term waterflooding, reservoir physical properties such as the pore throat structure and rock wettability may change. In this paper, the relative permeability curves under different water injection volumes through core-flood experiments were used to characterize the comprehensive changes of various reservoir physical properties at high water-cut stage. The novel concept of “water cross-surface flux” was proposed to characterize the cumulative flushing effect on the reservoir by injected water, and a novel method for inverted five-spot reservoir simulation at high water-cut stage based on time-varying relative permeability curves was established. From the relative permeability curves measured through two cores from the X oilfield under different water injection volumes (100, 500, 1000, 1500, and 2000 PV), it is found that with the increase of injected water volume, the two-phase co-flow zone becomes wider, the water permeability under residual oil saturation increases, and the residual oil saturation decreases. A waterflooding core model was established, simulated, and verified by the method proposed in this paper. It is found that using time-varying permeability curves for simulation, the highest oil recovery factor (61.58%) can be obtained with injected water volume up to 2000 PV, and the purpose of improved oil recovery (IOR) can be achieved by high water injection volume, but the increment is only approximately 10%. Besides, a waterflooding model of an inverted five-spot reservoir unit based on the X oilfield was also established, simulated, and analyzed. Simulation results have shown that no matter which set of core permeability curves measured from 100 to 2000 PV is directly used alone, the oil recovery factor will be simulated inaccurately. The findings of this study can help in better understanding the quantitative description of the oil recovery changes with time-varying reservoir physical properties in high water-cut reservoirs during waterflooding.

Effects of progressive dolomitization on reservoir evolution: A case from the Permian–Triassic gas reservoirs of the Persian Gulf, offshore Iran

Dolostones are among the most important reservoir units within the Permian–Triassic Dalan and Kangan formations throughout the central Persian Gulf. In this study, petrographic and geochemical (carbonate carbon and oxygen isotopes) analyses led to the identification of several dolomitization phases from sabkha and hypersaline to burial diagenetic realms. An integration of the estimated temperatures of dolomites and their textural properties results in the differentiation of three thermal domains of dolomitization including low (LTD; < 30 °C), moderate (MDT; 30–50 °C), and high (HDT; > 50 °C) temperature dolomites. They are respectively associated with primary/fabric retentive and early micro-fabric destructive, late micro-fabric destructive, and fabric destructive (recrystallization) and saddle dolomites. Combination of petrographic, geochemical, and petrophysical results (core porosity and permeability, and pore-throat size distribution) shows a good correlation between the higher estimated temperatures of dolomites and progressive destruction of the primary depositional textures, larger crystal sizes, and higher porosity and permeability values. In general, the late micro-fabric destructive, wholly fabric destructive, and recrystallized dolomites led to the improvement of flow capacity in the studied intervals via increasing pore-throat size, decreasing tortuosity, and enlarging the crystal size.

Tectonostratigraphic evolution of the Helleh Paleo-high (NW Persian Gulf): Insights from 2D and 3D restoration methods

Seismic and well data, restored cross sections and surfaces, as well as non-seismic data were utilized to reconstruct the tectonostratigraphic evolution of the Helleh Paleo-high, a gentle, elongated, N-NE trending structure in the Iranian sector of NW Persian Gulf. Based on Bouguer gravity anomaly and basement depth maps, the southeastern margin of the Helleh Paleo-high is defined by the Bushehr Fault, a NE-SW trending deep-seated fault which contributed to the deposition of thicker late Precambrian-early Cambrian Hormuz Salt to the SE. There is also a significant increase in thickness of the Late Devonian to latest Triassic succession in the southeastern block of this fault, a feature which is interpreted as evidence for syn-depositional fault activity.After a period of relative tectonic quiescence during the Jurassic and Early Cretaceous, the Helleh Paleo-high became emerged and eroded from the Cenomanian to Maastrichtian-early Paleocene. Uplift and erosion continued until the early Miocene, but at lower rates compared to the Late Cretaceous. The repeated reactivations of the Bushehr Fault together with the remobilization of the Hormuz Salt in the core area of the Helleh Paleo-high could have contributed to these phases of amplified erosion.In the early Miocene, the peripheral loading related to the southward advance of the Zagros Fold and Thrust Belt resulted in the establishment of the Zagros foredeep basin. This event exerted a NE downward tilting on the Helleh Paleo-high. The progressive tilting continued during the middle Miocene when the structure attained its maximum extent as a 4-way closure. The latest Miocene- Pleistocene was a critical period in the structural history of the Helleh Paleo-high when the final stage of Zagros foredeep basin evolution tilted the structure to such a degree that all pre-existing structural reliefs in the post- Upper Triassic reservoir units were completely destroyed. In fact, the Helleh Paleo-high is an example of a damaged hydrocarbon trap due to recent tectonic tilting.

Sedimentologic and stratigraphic properties of Early Cretaceous Neo-Tethys shelf margin of Arabia: The Qamchuqa Formation of the Zagros Folded zone – Kurdistan Region of Iraq

The Qamchuqa Formation is well-exposed in the High Folded Zone (HFZ) of northeast Iraq. The formation is highly dolomitized and contains thick reservoir units in the subsurface region south of the HFZ. Deposition of the formation took place at the shelf margin of Early Cretaceous Neo-Tethys Ocean. It merges south- and southeastward to the shallow marine shelf of Arabia and to deep basin accumulations farther north. In the study area, the formation is divided into three members: lower member (250m thick) of interbedded bioclastic calcimudstone/wackestone (MW), bioclastic packstone (BP), bioclastic floatstone (BF) and medium-to coarse-crystalline dolorudstone/dolograinstone (CD). These strata accumulated in low to medium energy, subtidal, fore-shoal setting. The middle member consists of thick succession (325m) of massively bedded CD lithofacies interpreted as high energy shoal facies which represents Barremian-Aptian main shelf-margin succession. The upper member (155m thick) consists of three lithofacies of MW, CD and fine crystalline dolomudstone (FD), in ascending order. It is interpreted as lagoon (MW) through subtidal carbonate sand shoal (CD) to supratidal (penecontemporaneous) dolomudstone (FD). The lower two members represent a long-term Barremian to Aptian shallowing-upward megacycle capped by late Aptian unconformity incurred by relative sea level drop. This temporal gap is coeval with an erosional vacuity recognized throughout the Arabian Peninsula. Sea level rise in early Albian heralded deposition of the upper member which also represents a shallowing-upward cycle surmounted by regionally extensive subaerial unconformity recognized in the Arabian Peninsula. Correlation and stratigraphic position of the formation under regional context has been discussed.

Investigation and prediction of diagenetic facies using well logs in tight gas reservoirs: Evidences from the Xu-2 member in the Xinchang structural belt of the western Sichuan Basin, western China

The second member of the Xujiahe Formation (Xu-2 Member) is one of the most significant gas reservoir units in the Sichuan Basin. The Xu-2 sandstones in the Xinchang structural belt are characterized by tight reservoirs with both low porosity and low permeability owing to diagenetic effects. The tight sandstones are commonly deeply buried and test samples from cores for research are limited. Therefore the investigation of diagenesis and diagenetic facies using well logs is reasonable and necessary. The Xu-2 sandstones are mainly litharenites, with less lithic quartz arenite and feldspathic litharenite. Secondary pores make up the majority of tight reservoir porosity, while remaining primary pores are still observable. Diagenetic minerals are mainly composed of carbonates, quartz cement and clay minerals. Carbonate and quartz cementation are two key reservoir quality destructive mechanisms. Illite generally has an important influence on diminishing the reservoir quality, whereas chlorite is associated with primary pore preservation. Five diagenetic facies are recognized, namely, tightly compacted facies, dissolution facies, carbonate cemented facies, quartz cemented facies and clay mineral cemented facies. By correlating diagenetic facies with characteristics of well log responses, various diagenetic facies can be recognized, even in the intervals that lack core control. Tightly compacted and dissolution facies are the two key diagenetic facies in the target stratum of the study area, with favorable reservoirs generally associated with the dissolution facies.

Integrated seismic and well-log analysis for the exploration of stratigraphic traps in the Carbonera Formation, Llanos foreland basin of Colombia

The Llanos foreland basin of Colombia is the country's most prolific oil producer, with the most known oil fields found in normal fault traps created during flexure of the foreland basin. The objective of the study is to evaluate the potential of stratigraphic traps in the Late Eocene-Early Miocene Carbonera Formation, a 400-1800 m-thick reservoir unit with numerous traps related to unfaulted, sand-prone fluvial deposits. We integrated 700 km2 of 3D seismic data with eight wells near the ~8600 bcd Cubiro field in the central area of the Llanos foreland. Interpretations of well logs and stratal slices through multi-attribute and iso-frequency amplitude cubes show that the Carbonera Formation contains tectonically-controlled, sinuous channel belts seen on seismic lines as strong, high-amplitude, concave reflections with variable width-to-depth ratio. Well logs through the Carbonera Formation record two regressive-transgressive cycles with greater preservation of non-reservoir, shaly transgressive deposits within the intermediate Carbonera members 5 and 3, and sandy, lowstand deposits in the lower and uppermost Carbonera members 7 and 1, respectively. Seismic and gamma-ray facies analyses allowed the distinction of prospective, sand-rich point bars, scrolls, and basal lag deposits from non-prospective, mud-rich abandoned channels. Stratal slices within the Carbonera Formation show changes from Late Eocene-Early Oligocene, northeast-flowing channel belts of a main axial fluvial system -proposed to be the proto-Meta River-, to a Late Oligocene southeast-flowing tributary channels interpreted as a result of eastward flexural migration, enhanced accommodation from loading of the Eastern Cordillera and a shift from an underfilled to overfilled foreland basin.

Evaluating the reservoir properties of Nahr Umr Formation at Luhais oil field, southern Iraq using well logs data

Nahr Umr formation in the oilfield of Luhais in southern Iraq is one of productive clastic reservoirs which formed during the secondary Alpine cycle. To cover the objectives of this study, twenty two wells were selected to evaluate the reservoir characteristics of the Nahr Umr formation in Luhais oilfield in southern Iraq. The petrophysical characteristics (Shale Volume (Vsh), Bulk volume hydrocarbon (BVH), Hydrocarbon saturation (Sh), Water saturation (Sw), thickness, Bulk water volume (BVW), porosity (φ ) were calculated and interpreted using the Geolog software. The Nahr Umr Formation was divided into three main reservoir units based on their petrophysical properties, these units are: Upper Nahr Umr reservoir unit, Middle Nahr Umr reservoir unit and Lower Nahr Umr reservoir unit. It was found that the best reservoir units in terms of hydrocarbon saturation and production are the middle Nahr Umr reservoir unit.

The geochemistry of produced waters from the Tuscaloosa Marine Shale, USA

Produced water is a byproduct of oil and gas production. The chemistry of produced water may provide information about the source of the fluid and its evolution, leading to an improved understanding of the hydrology of petroleum systems. In this study, samples from 19 wells from the Tuscaloosa Marine Shale (TMS) in Mississippi and Louisiana, USA were analyzed for their major and trace element compositions. Data obtained from produced waters from the TMS were compared to existing chemical data from produced waters collected from nearby hydrocarbon reservoir rocks within the Gulf Coast Basin. The results show that produced waters from the TMS are highly saline, with a mean concentration of 15.9 g/L of total dissolved solids. Comparison of the chemistry of produced water from the TMS to early flowback waters demonstrated a rapid shift from the more dilute fracturing fluid to the formation water endmember composition. Most of the trace metals showed a moderate to strong correlation with the overall salinity of the waters. Concentrations of Cu and V showed a moderate correlation with the amount of oil produced from the TMS wells, suggesting that these elements are strongly affiliated with the kerogen and subsequent dissolved (<0.45 μm) organic phases. Analysis of the volume of produced water compared to the volume of water used during hydraulic fracturing indicates that 15%–110% of the water volume used for fracking had been returned to the surface over the 2–5 year production period of the sampled wells. Chloride to bromide ratios suggest that the formation water in the TMS was derived from evaporated seawater. Comparison to historical data for produced waters in other formations in and around the Mississippi Salt Basin showed that waters in all the formations had a consistent origin (bitterns likely derived from the formation of the Louann salt). This implies that over geologic time periods fluids migrated through the TMS despite its low permeability present-day. The TMS also exhibited lower concentrations of dissolved transition metals such as Zn and Pb relative to those described in adjacent formations. This observation may suggest the presence of larger amounts of H2S, limiting the solubility of sulfide phases, in the shale unit relative to adjacent reservoir units.

PETROLEUM GEOLOGY OF THE WESTERN PART OF THE CENTRAL IRAN BASIN

Eocene extension and magmatism in Central Iran was followed by late Eocene – early Oligocene uplift, erosion, volcanism and the deposition of the continental and evaporitic sediments of the Lower Red Formation. During the late Oligocene – early Miocene, an extensional (or transtensional) phase occurred with the deposition of the limestones and marls of the Qom Formation, followed by the evaporitic deposits or mudstones of the basal part of the Upper Red Formation. Since the late Miocene, compression has resulted in regional shortening and uplift, with the deposition of the thick, clastic‐dominated upper part of the Upper Red Formation and the overlying conglomeratic unit.Between 1951 and 2016, a total of 45 exploration, appraisal and development wells were drilled across the western part of the Central Iran Basin where the Alborz, Sarajeh and Aran fields are hydrocarbon discoveries. Traps at these fields are NW‐SE oriented detachment folds formed during the late Miocene – Pliocene. Porous and fractured limestones in the Qom e‐member are the principal reservoir units, and are capped by evaporites or mudstones in the basal part of the Upper Red Formation. Organic‐rich mudstones in the Qom e‐ and c‐members together with shales in the Jurassic Shemshak Formation are potential source rocks.An overview of 80 years of exploration efforts in the western part of the Central Iran Basin suggests that the main reasons for the general lack of success include drilling‐associated problems, poor reservoir characteristics, lack of hydrocarbon charge, and underestimating the thickness of the overburden on top of the Qom reservoir.

Petrophysical Analysis of an Iraqi Gas Field (Mansuriya Gas Field)

Mansuriya Gas field is an elongated anticlinal structure aligned from NW to SE, about 25 km long and 5-6 km wide. Jeribe formation is considered the main reservoir where it contains condensate fluid and has a uniform thickness of about 60 m. The reservoir is significantly over-pressured, (TPOC, 2014).&#x0D; This research is about well logs analysis, which involves the determination of Archie petrophysical parameters, water saturation, porosity, permeability and lithology. The interpretations and cross plots are done using Interactive Petrophysics (IP) V3.5 software.&#x0D; The rock parameters (a, m and n) values are important in determining the water saturation where (m) can be calculated by plotting the porosity from core and the formation factor from core on logarithmic scale for both and the slope which represent (m) then Pickett plot method is used to determine the other parameters after calculating Rw from water analysis .&#x0D; The Matrix Identification (MID), M-N and Density-Neutron crossplots indicates that the lithology of Jeribe Formation consists of dolomite, limestone with some anhydrite also gas-trend is clear in the Jeribe Formation.&#x0D; The main reservoir, Jeribe Formation carbonate, is subdivided into 8 zones namely J1 to J8, based mainly on porosity log (RHOB and NPHI) trend, DT trend and saturation trend.&#x0D; Jeribe formation was considered to be clean in terms of shale content .The higher gamma ray because of the uranium component which is often associated with dolomitisationl and when it is removed and only comprises the thorium and potassium-40 contributions, showed the gamma response to be low compared to the total gamma ray response that also contains the uranium contribution.While the Jeribe formation is considered to be clean in terms of shale content so the total porosity is equal to the effective porosity.No porosity cut off is found if cutoff permeability 0.01 md is applied while the porosity cut off approximately equal to 0.1 only for unit J6 &amp; J8 if cutoff permeability 0.1 md is applied .&#x0D; It can be concluded that no saturation cutoff for the units of Jeribe formation is found after a cross plot between water saturation and log porosity for the reservoir units of Jeribe formation and applied the calculated cut off porosity.&#x0D; The permeability has been predicted using two methods: FZI and Classical, the two methods yield approximately the same results for all wells.

Hydrocarbon leads and prospects opportunities across a cluster of fields in parts of Onshore Niger Delta Basin

The increase in oil and gas production over the years from already discovered fields at relatively shallower intervals, and corresponding decrease in the discovery of new fields has led to observable decline in the available hydrocarbon reserves within the Niger Delta Basin of Nigeria. Therefore, there is need to grow or add to the existing reserves through “searching wider and drilling deeper” across the onshore sector of the Niger Delta Basin, which is the focus of this work. Although, there has been several hydrocarbon prospectivity studies in the Onshore Niger Delta Basin, most of these studies were conducted on individual fields, except where adjacent fields belonged to the same operator. This has provided limited information on stratigraphic intervals, structural features and reservoir zones continuity across several fields. This study is aimed at interpreting recently acquired within the Coastal Swamp Depobelt of the Niger Delta, long-cable regional 3D seismic data over nine producing fields, and data from twenty-five wells, using sequence stratigraphic, structural and reservoir exploration tools, thus providing a regional scale interpretation and information that will unravel new prospective zones across these fields primarily based on amplitude supported structural plays. Results from stratigraphic studies, show the occurrence of regional extensive chrono/sequence stratigraphic surfaces such as maximum flooding surfaces (7.4–12.8 Ma) and sequence boundaries (8.5–13.1 Ma) that depict sediment packages deposited during the Middle-Miocene through Upper Miocene age. Well log sequence stratigraphic and reservoir correlation studies reveal that depositional sequences, bounded by these surfaces, comprise reservoir and non-reservoir packages within their systems tracts. Reservoir architectural studies show sands of lowstand, transgressive, and highstand systems tracts that make up the reservoir units, are relatively thick, laterally continuous and quite extensive across the area. Interpreted seismic sections unravelled the influence of structure on stratigraphy as sediment packages show variable thicknesses across faults. This was linked to syndepositional deformation associated with sediment deposition within the basin. Mapped reservoir tops at intermediate and deeper intervals reveal the dominance of fault-dependent closures. In addition, root mean square amplitude extraction done on these maps, unravelled eight structurally controlled regional hydrocarbon prospects and eight leads with booming amplitude responses that are conformable to structures. Overall, this study has shown that there exist hydrocarbon prospective zones that cut across several fields at deeper depths that are yet to be drilled, which could contribute to the Niger Delta Basin's existing reserve base.

Petrophysical Investigation of the Khurmala Formation in Taq Taq Oil Field, Zagros Folded Belt

The Tertiary rocks of Khurmala Formation in the Taq Taq oil field have been studied using wireline log analysis, drilling cutting descriptions with integration of mud logging report, and test results for understanding reservoir potentiality and fluid distribution. The formation comprised dolostone and dolomitic limestone with an intercalation of clay layers between the recognized beds. The formation has variable thickness throughout the field, 99.8 m from the northeastern limb and 109 m in the southeastern plunge. The calculated shale volume in the studied interval shows a high rate of the clay contents which in some points the gamma ray has 100% of shale. The corrected log-derived bulk porosity subdivided the Khurmala Formation into 5 porosity units from the top to the bottom including (Kh-1, Kh-2, Kh-3, Kh-4, and Kh-5). The first (Kh-1), third (Kh-3), and fifth (Kh-5) porosity units have the average porosity ≥0.10 (10%) that can be considered as good reservoir unit in terms of porosity, whereas the shale contents reduced the reservoir quality of these units. However, well hydrocarbon entrapment through interconnected fractures and fault in the other Tertiary reservoir was recorded in Taq Taq field , but the weak connectivity of the pores in the Khurmala Formation caused this rock interval remains as water bearing zone.

Characterization of the Rapanui mass‐transport deposit and the basal shear zone: Mount Messenger Formation, Taranaki Basin, New Zealand

AbstractSubmarine mass‐transport deposits are important in many ancient and modern basins. Mass‐transport deposits can play a significant role in exploration as reservoir, seal or source units. Although seismic data has advanced the knowledge about these deposits, more outcrop studies are needed to better understand gravity mass flows and predict the properties of their resultant deposits. It is proposed that sufficiently well‐exposed outcrops of mass‐transport deposits can be divided into three strain‐dominant morphodomains: headwall, translational and toe. The outcrops of the Rapanui mass‐transport deposit, part of the Lower Mount Messenger Formation in the Taranaki Basin, New Zealand, are exposed along a ca 4 km transect in coastal cliffs that enable the identification of the three morphodomains. The aim of this study is to characterize the stratigraphic and sedimentological nature of the Miocene‐age Rapanui mass‐transport deposit outcrops and the evolution of its basal shear zone. The basal shear zone of a mass‐transport deposit is defined as the stratal zone formed in the interface between the overriding mass flow and the underlying in situ deposits or sea floor. Accordingly, the deformation structures in the Rapanui mass‐transport deposit and the basal shear zone were documented in an established spatial framework. Traditional methodologies were used to characterize the sedimentology of the Rapanui mass‐transport deposit. Data collected from intrafolial folds, rafted blocks and samples from the Rapanui mass‐transport deposit were used to investigate strain and matrix texture evolution, estimate palaeoflow direction, and calculate yield strength and overpressure at time of deposition. Additionally, a one‐dimensional numerical model was used to test sedimentation‐driven overpressure as probable trigger. This work demonstrates that the basal shear zone, as well as the matrix texture of a mass‐transport deposit, can vary spatially as sediments from underlying deposits are entrained during shear‐derived mixing. This phenomenon can impact the seal potential of mass‐transport deposits and their interaction with fluids in the subsurface.

Integration of well logs and seismic data for hydrocarbon volumetric analysis in done field of the Niger Delta Region, Nigeria

The study was carried out on an onshore Niger Delta field using seven wells with the objectives of identifying possible reservoir units with potential to contain oil or gas using well logs and seismic data sets. Petrophysical properties analysis revealed two Hydrocarbon bearing reservoirs ranging from 5000 ft – 8000 ft, with volume of shale (Vsh) ranging from 4.3% - 43.9%. The total porosity ranged from 25.9% - 34.7%, while effective porosity ranged from 17.7% - 33.2%, indicating good porosities for the reservoirs. Net-to-Gross ranged from 0.720 – 0.980 with water saturation ranging from 19.87% - 29.07%, while hydrocarbon saturation ranged from 70.93% - 78.86% of gas in the reservoirs. For the volumetric analysis of the two reservoirs modelled, a STOIIP ranging from 614MMSTB – 1054MMSTB was obtained, while the recoverable Oil was estimated between 215-369MMSTB. We can infer that the two reservoirs mapped, correlated and modelled across the seven wells has a respectable HC potential.Keywords: Well Logs, Seismic Data, Volumetric Analysis, Niger Delta

Prediction of Reservoir Quality from Log-Core and Seismic Inversion Analysis with an Artificial Neural Network: A Case Study from the Sawan Gas Field, Pakistan

This paper presents a novel approach that aims to predict better reservoir quality regions from seismic inversion and spatial distribution of key reservoir properties from well logs. The reliable estimation of lithology and reservoir parameters at sparsely located wells in the Sawan gas field is still a considerable challenge. This is due to three main reasons: (a) the extreme heterogeneity in the depositional environments, (b) sand-shale intercalations, and (c) repetition of textural changes from fine to coarse sandstone and very coarse sandstone in the reservoir units. In this particular study, machine learning (ML) inversion algorithm was selected to predict the spatial variations of acoustic impedance (AI), porosity, and saturation. While trained in a supervised mode, the support vector machine (SVM) inversion algorithm performed effectively in identifying and mapping individual reservoir properties to delineate and quantify fluid-rich zones. Meanwhile, the Sequential Gaussian Simulation (SGS) and Gaussian Indicator Simulation (GIS) algorithms were employed to determine the spatial variability of lithofacies and porosity from well logs and core analyses data. The calibration of the detailed spatial variations from post-stack seismic inversion using SVM and wireline logs data indicated an appropriate agreement, i.e., variations in AI is related to the variations in reservoir facies and parameters. From the current study, it was concluded that in a highly heterogeneous reservoir, the integration of SVM and GIS algorithms is a reliable approach to achieve the best estimation of the spatial distribution of detailed reservoir characteristics. The results obtained in this study would also be helpful to minimize the uncertainty in drilling, production, and injection in the Sawan gas field of Pakistan as well as other reservoirs worldwide with similar geological settings.

Quantitative characterization of diagenetic reservoir facies of the Karamay alluvial fan in the Junggar Basin, western China

The distribution of the remaining oil in developed oilfields is primarily influenced by the existing diagenetic reservoir facies (DRFs), which encompass the effects of both the sedimentary environment and the local diagenetic processes on the reservoir quality. We divided the Lower Karamay Formation reservoir samples into nine DRFs according to characteristics such as porosity, permeability, diagenetic intensity, and rock type. After applying the sequential indicator simulation methodology, we were able to create three-dimensional (3D) geological models of the DRFs. Based on these models, we can see that, during phases A and B of eodiagenesis, the prevailing DRF is a sandstone/sandy conglomerate that is moderately to weakly dissolved, moderately cemented, and characterized by moderate porosity and permeability values. The highest quality DRF, which emerged during the early stage of mesodiagenesis, is a sandstone/sandy conglomerate that is weakly compacted/cemented, moderately-to-strongly dissolved, and characterized by very high porosity and permeability values. By providing high-quality analyses of the DRFs in Block 6 of the Karamay oilfield, we provided vital information that allowed the operation to more efficiently target and extract oil from reservoir units that are already in production.

Using NMR, Core Analysis, and Well Logging Data to Predict Permeability of Carbonate Reservoirs: a Case Study

Fluid flow through porous media is a function of permeability for petroleum and gas reservoirs. This study investigated the distribution of permeability in the Mishrif formation in the Nasiriya oilfield. The value of effective porosity was obtained from well log data and used to predict permeability using three methods: applied empirical correlations using interactive Petrophysics (IP) software (Version 3.5), core data measurements, and nuclear magnetic resonance (NMR). Nasiriya oil field is one of the large oil fields in southern Iraq, and the Mishrif formation, the area of the case study, consists of the following units from top to bottom: a cap rocks unit; the Upper Mishrif (unit 1); a shale unit; the first reservoir unit (2), a Barrier rocks unit; and the second reservoir unit (3). A 3D model was built by using Petrel software (2009), and the LAS files used to digitize the contour map of the reservoir layers were obtained from Didger3 software. The total number of 3D grids in the model was 5,394,480, with 336 grids in the I direction, 169 in the J direction and 95 in the k direction. Scaling up was done by using the geometric method for permeability, and sequential Gaussian simulation was used in the distribution of petrophysical properties. The results of distribution showed the importance of each zone and the best permeability value was recorded in the second reservoir layer, which varied from 1 md to 100 md.