Artificial Lift Optimization for Shallow Carbonate Magwa and Ostracod Formations with Massive Propped Fractures

Objectives/Scope: The Magwa and Ostracod formations are tight and highly fractured carbonate reservoirs. At shallow depth (1600-1800 ft) and low stresses, wide, long and conductive propped fracture has proven to be the most effective stimulation technique for production enhancement. However, optimizing flow of the medium viscosity oil (17-27 API gravity) was a challenge both at initial phase (fracture fluid recovery and proppant flowback risks) and long-term (depletion, increasing water cut, emulsion tendency). Methods, Procedures, Process: Historically, due to shallow depth, low reservoir pressure and low GOR, the optimum artificial lift method for the wells completed in the Magwa and Ostracod reservoirs was always sucker-rod pumps (SRP) with more than 300 wells completed to date. In 2019 a pilot re-development project was initiated to unlock reservoir potential and enhance productivity by introducing a massive high-volume propped fracturing stimulation that increased production rates by several folds. Consequently, initial production rates and drawdown had to be modelled to ensure proppant pack stability. Long-term artificial lift (AL) design was optimized using developed workflow based on reservoir modelling, available post-fracturing well testing data and production history match. Results, Observations, Conclusions: Initial production results, in 16 vertical and slanted wells, were encouraging with an average 90 days production 4 to 8 times higher than of existing wells. However, the initial high gas volume and pressure is not favourable for SRP. In order to manage this, flexible AL approach was taken. Gas lift was preferred in the beginning and once the production falls below pre-defined PI and GOR, a conversion to SRP was done. Gas lift proved advantageous in handling solids such as residual proppant and in making sure that the well is free of solids before installing the pump. Continuous gas lift regime adjustments were taken to maximize drawdown. Periodical FBHP surveys were performed to calibrate the single well model for nodal analysis. However, there limitations were present in terms of maximizing the drawdown on one side and the high potential of forming GL induced emulsion on the other side. Horizontal wells with multi-stage fracturing are common field development method for such tight formations. However, in geological conditions of shallow and low temperature environment it represented a significant challenge to achieve fast and sufficient fracture fluid recovery by volume from multiple fractures without deteriorating the proppant pack stability. This paper outlines local solutions and a tailored workflow that were taken to optimize the production performance and give the brown field a second chance. Novel/Additive Information: Overcoming the different production challenges through AL is one of the keys to unlock the reservoir potential for full field re-development. The Magwa and Ostracod formations are unique for stimulation applications for shallow depth and range of reservoirs and fracture related uncertainties. An agile and flexible approach to AL allowed achieving the full technical potential of the wells and converted the project to a field development phase. The lessons learnt and resulting workflow demonstrate significant value in growing AL projects in tight and shallow formations globally.

Integration of Advanced Logging Evaluation Techniques Proves Additional Reserves from Thin Bed, Low Resistivity Pay Formations

The biggest clastic reservoir based in Kuwait has been facing evaluation challenges over the thick intervals of highly laminated thin hydrocarbon layers. Conventional wireline tools have a limitation on resolution when it comes to addressing these thin beds. Therefore, the reserves are usually underestimated, and thin pays are often overlooked. This paper presents the integration of a variety of advanced Wireline tools in order to correctly evaluate and compute reserves from these thin pay zones. Acquisition of the triaxial induction tool enabled the study of resistivity anisotropy and the identification of thin pay zones through the distinct reading of the resistivity of the thin sand reservoir. The thin layers have also been further validated using high resolution advanced thin bed analysis from image logs. Advanced spectroscopy and NMR data were used to quantitively define the sand and shale fractions within the thin beds. These measurements were critical to input to improve the resistivity interpretation followed by a reliable estimate of the saturation. High resolution dielectric measurements provided resistivity-independent saturation information enhancing the NMR interpretation using water-filled porosity which was a key input into the identification of the heavy oil presence in Burgan. The newly identified thin pay zones have been further validated using the fluid sampling confirming presence of hydrocarbons with greater understanding of its properties and uniquely quantifying the mobile fluid fractions. The additional available reserves can only be properly determined by combining data from multiple sources to achieve a comprehensive evaluation. Resistivity anisotropy was observed based on the separation of vertical and horizontal resistivities and was therefore investigated to understand its root-cause over different zones. By integrating the results from the dielectric dispersion measurements, the diffusion-based NMR data, spectroscopy data, borehole image interpretation and high-resolution sand count delineation of different lithologic units at a finer scale, we were able to identify thin bedded sand-shale intervals in addition to pin-pointing the heavy oil intervals. Hydrocarbon saturations of individual sand layers showed improvement in hydrocarbon volumes, improvement in permeabilities across the studied zones and increased net pay estimations by 12%. Results from the fluid sampling performed across the newly identified thin pays have validated the advanced logging interpretation results and the presence of hydrocarbons. These intervals were overlooked by the standard basic evaluation and the reservoir potential has been revisited following the latest integrated advanced results. By combining the results of all these advanced wireline answer products, we were able to properly identify and quantify the additional available reserves and therefore change the classification of these reservoirs from poor to excellent with new development plan in place. The paper demonstrates the value solution of the high vertical resolutions taking advantage of the latest advanced technologies to enhance the characterization of laminated thin beds. The integrated advanced solution has enabled improved reservoir potential by the identification of new pay zones initially overlooked by the standard basic measurements.

Sedimentology and depositional environments of Murihiku Supergroup sediments exposed in the Southland Syncline, New Zealand: Implications for reservoir potential in the Great South Basin

<p>A considerable amount is known about the biostratigraphy and organic geochemistry of the Murihiku Supergroup sediments exposed in coastal outcrops of the Southland Syncline, New Zealand. Much less work has been undertaken on the sedimentology of these strata, or understanding their depositional environments and depositional trends through time. What these implications are for reservoir prospectivity in the adjacent Great South Basin, has also had little study focused on it. This thesis addresses these issues by undertaking outcrop-based sedimentological and facies interpretations of these rocks, thin-section based petrographic composition and provenance analysis, augmented by X-Ray Diffraction (XRD) and Scanning Electron Microscopy (SEM), as well as porosity and permeability measurements from outcrop core plugs. Petroleum industry seismic data has additionally enabled seismic facies mapping of Murihiku rocks in the offshore Great South Basin. Outcrop observations point to a progressive change in depositional setting, from shelf / upper slope settings during the Late Triassic, to base of slope turbidite deposition in the Early Jurassic. This transgression is followed by regression into fluvial settings in the youngest outcropping Murihiku rocks in the study of Middle Jurassic age. Petrographically the sandstones are feldspathic and lithic arenites and feldspathic and lithic wackes. Provenance suggests derivation from an evolving, intermediate arc that was becoming more siliceous through Late Triassic and Middle Jurassic time. Diagenesis is characterised by early calcite and chlorite precipitation which have almost completely destroyed any primary porosity. Any secondary micro porosity has subsequently been infilled through dissolution of framework grains and zeolitization. SEM and core plug porosity and permeability measurements corroborate the diagenetic changes observed petrographically, with only fluvial facies of Middle Jurassic (Upper Temaikan) age showing any measureable porosity or permeability. As a result, reservoir potential for the Late Triassic to Middle Jurassic, Murihiku Supergroup rocks analysed in this study is low. Younger Murihiku sandstones which are postulated to occur offshore in the Great South Basin are likely to be less influenced by burial diagenesis. As shown from North Island occurrences, these younger successions hold some potential.The reservoir potential for these youngest portions of the Murihiku succession therefore remains positive, both in the Great South Basin, as well as other frontier areas of Zealandia, and continue to provide an exploration target for the petroleum industry.</p>

Sedimentology and depositional environments of Murihiku Supergroup sediments exposed in the Southland Syncline, New Zealand: Implications for reservoir potential in the Great South Basin

<p>A considerable amount is known about the biostratigraphy and organic geochemistry of the Murihiku Supergroup sediments exposed in coastal outcrops of the Southland Syncline, New Zealand. Much less work has been undertaken on the sedimentology of these strata, or understanding their depositional environments and depositional trends through time. What these implications are for reservoir prospectivity in the adjacent Great South Basin, has also had little study focused on it. This thesis addresses these issues by undertaking outcrop-based sedimentological and facies interpretations of these rocks, thin-section based petrographic composition and provenance analysis, augmented by X-Ray Diffraction (XRD) and Scanning Electron Microscopy (SEM), as well as porosity and permeability measurements from outcrop core plugs. Petroleum industry seismic data has additionally enabled seismic facies mapping of Murihiku rocks in the offshore Great South Basin. Outcrop observations point to a progressive change in depositional setting, from shelf / upper slope settings during the Late Triassic, to base of slope turbidite deposition in the Early Jurassic. This transgression is followed by regression into fluvial settings in the youngest outcropping Murihiku rocks in the study of Middle Jurassic age. Petrographically the sandstones are feldspathic and lithic arenites and feldspathic and lithic wackes. Provenance suggests derivation from an evolving, intermediate arc that was becoming more siliceous through Late Triassic and Middle Jurassic time. Diagenesis is characterised by early calcite and chlorite precipitation which have almost completely destroyed any primary porosity. Any secondary micro porosity has subsequently been infilled through dissolution of framework grains and zeolitization. SEM and core plug porosity and permeability measurements corroborate the diagenetic changes observed petrographically, with only fluvial facies of Middle Jurassic (Upper Temaikan) age showing any measureable porosity or permeability. As a result, reservoir potential for the Late Triassic to Middle Jurassic, Murihiku Supergroup rocks analysed in this study is low. Younger Murihiku sandstones which are postulated to occur offshore in the Great South Basin are likely to be less influenced by burial diagenesis. As shown from North Island occurrences, these younger successions hold some potential.The reservoir potential for these youngest portions of the Murihiku succession therefore remains positive, both in the Great South Basin, as well as other frontier areas of Zealandia, and continue to provide an exploration target for the petroleum industry.</p>

Assessment of the facial affiliation of local oil and gas objects based on geophysical data

In the established practice of geological exploration for oil and gas conclusions about the facies belonging of the rocks of oil and gas basins and individual exploration areas were made mainly on the basis of the study of core material. Recently for this purpose the results of seismic exploration and well logging have been used. Geophysical methods despite their obvious progress are indirect and intermittent core sampling and incomplete coring make facies analysis difficult. Тhe study of cuttings during the well logging process makes it possible to fill this gap through direct continuous observations along the well section. The use of the whole complex of geophysical methods allows one to mutually compensate for the limitations and disadvantages of each of them and more fully and reliably assess the genetic characteristics and reservoir potential of productive deposits. Sequential accumulation, comparison and analysis of heterogeneous geophysical data make it possible to continuously refine apriori facies models and forecast oil and gas content which ultimately allows to optimize the directions and volumes of drilling.

Petrofacies investigations of the Cretaceous Pab Formation Rakhi Gorge Eastern Sulaiman Range Pakistan - Implication for reservoir potential

Petrologic investigations of the sixty representative thin sections from the Pab Formation within Rakhi Gorge section Eastern Sulaiman Range Pakistan have been used to characterize different diagenetic patterns, identification of primary composition and reservoir characters. Sublithic, lithic and quartzose sandstones have been the principal constituents of the formation. The processes responsible for the late-stage alteration and diagenetic processes identified during the petrographic study include compaction of lithic fragments and mud clasts, formation of quartz overgrowth structures, feldspar replacement and alteration, cementation, and replacement of grains by clay minerals other ferrous elements and diagenetic minerals. The study shows that the initial porosity has been primary intergranular, but the secondary porosity has been originated in the rocks as a result of the alteration of the primary and secondary constituents, as well as fracturing. These facies characters replicate the reservoir quality including, good, medium, low-quality, and non-reservoir. Samples displaying average total porosity greater than 10 % have been declared as good quality. While rocks samples having 7 % or greater porosity are grouped as a medium reservoir. Those samples consisting of porosity values between 1 and 4% are considered as a low quality reservoir while those samples having porosity ranges low than 1% have been called non-reservoir. Based on the investigated parameters the studied samples from the Pab Formation displayed the characters of a medium reservoir that may hold significant hydrocarbon. This different quality including good and low quality zonation can be attributed to the facies and diagenetic change in the formation.

Petrophysical properties of bypassed Cenozoic clastic reservoirs in the Cesar sub-basin, Colombia

The Cesar-Ranchería basin has all the necessary elements for the generation, expulsion, and migration of hydrocarbons and considerable potential for coal bed methane (CBM) in Colombia. Previous studies in the Cesar basin focused on understanding the tectonic evolution, stratigraphy, hydrocarbon generation potential, and evaluation of reservoir potential in Cretaceous calcareous units and quartzose sandstones from the Paleocene Barco Formation. These studies had confirmed the existence of an effective petroleum system, with several episodes of oil expulsion and re-emigration in the Miocene period, turning the Cenozoic clastic succession (Barco, Los Cuervos, La Loma, and Cuesta formations) into an element of significant exploratory interest to clarify the potentiality of the basin in terms of hydrocarbon accumulation. The petrophysical parameters of Cenozoic units (shale volume, porosity, water, and oil saturation) were determined by integrating wells log and core samples analyses from three stratigraphic wells. The integration of these results synthesizes the petrophysical behavior of the units. It defines intervals with clay volumes of less than 30%, effective porosity around 20%, which means favorable characteristics as reservoir rocks that need to be considered in future exploratory projects.

Red Sea Holocene carbonates: Windward platform margin and lagoon near Al-Wajh, northern Saudi Arabia

ABSTRACT Analysis of Holocene sedimentary seascape is focused on the Red Sea windward Al-Wajh platform margin, its central lagoon, and nearby isolated platforms based on data that include mapped ecological facies (habitats), water depths, grain sizes, and allochem types and abundances determined from thin sections. On this basis, a depositional model applicable to Red Sea Plio-Pleistocene and other ancient icehouse carbonate platforms is presented. The model highlights favorable reservoirs in analogous ancient systems to include coral crests and columnar framework habitats with primary porosity developed in boundstone lithologies and windward platform margins to contain considerable open pore space, including cavernous openings, of which not all should be anticipated to be occluded with marine cements and sediments. Meteoric diagenesis is expected to be minor as limited freshwater is available due to extreme aridity, but may play a role during glaciation. Most habitats have potential for secondary (enhanced) porosity resulting from dissolution of aragonite skeletons, particularly mollusk shells and calcareous coral (Scleractinia) endoskeletons. Central-lagoon habitats are expected to have the least favorable reservoir potential of environments considered because they are dominated by peloids. Central-lagoon sediment differs from other published localities, having higher peloid abundances, greater peloid distribution, and little or no association with Halimeda and quartz grains. Under the likely scenario that platform-interior sediments are completely bioturbated and comprise peloid-rich, grain-dominated fabrics, with many smaller peloids (most of them likely fecal pellets) at or near 4 μm in size (i.e., mud fraction), it is possible that grain size will control pore size once the considered deposits are lithified. If so, platform-interior sediments will lithify as mudstones, wackestones, or very fine-grained grainstones, an outcome which might otherwise be unexpected given the abundance of coarse peloid grains. The Al-Wajh platform is compared with 15 Holocene analogs and found to be unique with respect to rift-margin type, restricted-marine circulation, in having a lagoon with high peloid content, and lack of karst. In further comparison with ancient reservoir analogs, two greenhouse and four icehouse, it compares favorably to icehouse platforms deposited in rift basins with respect to mineralogy of deposition, meter-scale cycle thicknesses, and general peloid content and distribution. It provides a snapshot as to how an icehouse platform might have nucleated and attached along an active rift margin; it is a broadly applicable carbonate analog for the Red Sea Plio-Pleistocene and similar icehouse, rift basins.

Controls on sediment distribution in a volcanically-affected basin: insights from the Ethiopian Flood Basalt Province

This study provides a comprehensive examination of the Oligocene–Miocene Ethiopian Flood Basalt Province (EFBP) within the Blue Nile (Abay) Basin (BNB), Ethiopia. Extensive logging through 29 new sections has enabled an updated stratigraphic account of the BNB to be elucidated and reveals the significance of intravolcanic sedimentary systems within the EFBP. Five sub- and intra-volcanic surfaces were modelled using spot heights to generate isopach maps that were used to constrain the thickness variations within the stratigraphy. Additionally, lineaments, Strahler stream segments and volcanic cones were mapped out from digital elevation models (SRTM DEM) and satellite data (ASTER and LANDSAT 8 imagery). These data were used in conjunction with the isopach maps to better understand the basinal controls on the distribution of intravolcanic sedimentary systems within the BNB. The study reveals how NNE and ESE/SE structural trends have influenced the distribution of volcanoes within the basin, which has in turn disrupted the distribution and lithofacies architecture of the volcanic sequences. The presence of intrabasinal ridges parallel to the major structural trends are also revealed, which formed relatively short-lived drainage divides. The implications of these intrabasinal highs on the composition and the reservoir potential of intravolcanic sedimentary successions are discussed.