Petrophysical core-based zonation of OW oilfield in the Bredasdorp Basin South Africa

This study aims to generate rock units based on core permeability and porosity of OW oilfield in the Bredasdorp Basin offshore South Africa. In this study, we identified and classified lithofacies based on sedimentology reports in conjunction with well logs. Lucia's petrophysical classification method is used to classify rocks into three classes. Results revealed three lithofacies as A (sandstone, coarse to medium-grained), B (fine to medium-grained sandstone), and C (carbonaceous claystone, finely laminated with siltstone). Lithofacies A is the best reservoir quality and corresponds to class 1, while lithofacies B and C correspond to class 2 and 3, which are good and poor reservoir quality rock, respectively. An integrated reservoir zonation for the rocks is based on four different zonation methods (Flow Zone indicator (FZI), Winland r35, Hydraulic conductivity (HC), and Stratigraphy modified Lorenz plot (SMLP)). Four flow zones Reservoir rock types (RRTs) were identified as RRT1, RRT3, RRT4, and RRT5, respectively. The RRT5 is the best reservoir quality composed of a megaporous rock unit, with an average FZI value between 5 and 10 µm, and HC from 40 to 120 mD/v3, ranked as very good. The most prolific flow units (RRT5 and RRT4 zones) form more than 75% of each well's flow capacities are supplied by two flow units (FU1 and FU3). The RRT1 is the most reduced rock quality composed of impervious and nanoporous rock. Quartz is the dominant framework grain, and siderite is the dominant cement that affects flow zones. This study has demonstrated a robust approach to delineate flow units in the OW oilfield. We have developed a useful regional petrophysical reservoir rock flow zonation model for clastic reservoir sediments. This study has produced, for the first time, insights into the petrophysical properties of the OW oilfield from the Bredasdorp Basin South Africa, based on integration of core and mineralogy data. A novel sandstone reservoir zonation classification criteria developed from this study can be applied to other datasets of sandstone reservoirs with confidence.

Application of in-plastic catalysis for extraction of hard-to-recover hydrocarbons

The object of research is the catalytic effect (hydrocracking) for the production of hard-to-recover hydrocarbons, the subject of the study is the change in the physicochemical properties of hydrocarbons by partial gasification, and the lightening of the fractional composition of hydrocarbons. One of the most problematic areas is the lack of studies of the catalytic effect on hard-to-recover hydrocarbons in reservoir conditions. Although processes such as catalytic cracking, reforming, isomerization, aromatization and alkylation of hydrocarbons are known and used in petroleum refining. The research used the methods of scientific knowledge – experiment and measurement. In the course of laboratory work, an effective catalyst was developed, the effect of temperature on the fractional composition and physicochemical properties of oil, oil products and gas condensate was investigated. To simulate formation conditions, hermetic metal retorts were used, in which oil and gas condensate samples were subjected to different temperature regimes. In the process of testing cores saturated with gas condensate, the dependence of filtration on physical parameters – temperature and pressure, fractional composition, specific gravity and viscosity was studied. Laboratory studies have shown a decrease in density and viscosity of hydrocarbons, an increase in core permeability. The effect of catalysis on oil made it possible to increase the volume of light ends distillation from 30 to 60 %, for gas condensate – up to 50 %, which confirms the effectiveness of the method of catalysis of hard-to-recover hydrocarbons. This is due to the fact that the correct formulation and solution of the problem provided adequate results. In contrast to the existing processes of hydrocracking of petroleum products, the proposed method allows you to extract heavy and low-mobile hydrocarbons in reservoir conditions at lower temperatures of 120–150 °С. At the same time, the technology for catalytic hydrogenation of hard-to-recover hydrocarbons will be similar to a typical treatment of a formation with an acid or surfactants. This will make it possible to intensify the commercial reserves of hydrocarbons in the fields that are now classified as hard-to-recover and which account for more than 50 %.

A Core Flood Test-Program Performed with a Pilot-Skid to Quantify the Permeability Decline Induced by Real Treated Produced Waters Also Containing Degraded Polymer or Not

A water treatment pilot skid called WaOω has been developed by TotalEnergies to test the efficiency of the centrifugation technology in treating the produced water containing back produced polymer. In case of success, this technology would be implemented on field and the water quality targeted by the technology must allow re-injecting the treated produced water in matrix flow regime for pressure maintain and sweep efficiency. The same interest was expressed by OMV and a partnership project has been built. It was also agreed that OMV builds a second pilot skid called PRT that allows carrying out core flood tests onsite to assess the formation damage and related permeability decline that could be induced by the treated produced water. Both pilot skids have been implemented, connected to each other, and tested during more than one year on the OMV's Matzen oil field nearby Vienna where degraded polymer is already back produced by wells and present in the produced water. More than seventy core flooding tests have been performed in different centrifugation conditions in terms of speed and water qualities, some of them on high permeable sand packs representing the field targeted by TotalEnergies and some others on consolidated sandstone samples of lower permeability representing OMV reservoirs. The effect of adding fresh polymer to the treated produced water for EOR purposes has also been investigated. Some complementary core flood tests have also been performed in TotalEnergies labs using reconstituted sand packs and produced waters with and without polymer to understand the contribution of the degraded polymer alone, the produced water quality alone and both to understand the formation damage and some uncommon results observed with the PRT pilot skid. Core flood tests data often obtained on long injection periods revealed of a high quality, reliable and reproducible. They also showed that even if centrifugation seems to be a good technology, the very clean and transparent water that it delivered induced surprisingly some core permeability declines the origin of which would be discussed in this paper. However, it was clearly established that the presence of degraded polymer has a cleaning effect and limits the formation damage induced by the produced water injected on cores if the Total Suspended Solids in the treated water remains at an acceptable level. Adding fresh polymers limited even more the formation damage because their cleaning effect is more pronounced than with degraded polymer.

Stimulation of Tight Formation in Kazakhstan by Chelate Based Treatment Fluids

Stimulation systems have improved over past decades, yet challenges prevail in corrosion, unwanted precipitation and handling hazardous chemicals. The role of chelating agents in coping with such concerns, is undeniably positive: their limited corrosivity, effective metal control and outstanding HSE profile, make them effective acidizing alternatives. Particularly when seeking delayed reaction at high temperature or removing insoluble material like Barite, chelating agents like GLDA and DTPA respectively have been reported effective both at laboratory and field scale. Formulations based on abovementioned chelating agents were evaluated experimentally to assess potential stimulation of Kazakhstan formations. Core-plug samples used in this evaluation are predominantly carbonate rock originating from different wells. The coreflooding experiments were performed at HPHT conditions to assess performance of treatment fluids to a) create new flow-channels (wormholes) thus improving rock permeability, and b) remove BaSO4-based solids suspected to be affecting productivity in the field. In this work, five reservoir core plugs were stimulated by GLDA based formulation to assess wormholing mechanism, while two core-plugs were treated by DTPA based fluid to study the impact of matrix cleaning. The matrix cleaning properties of DTPA based fluid were investigated on the damaged core plugs which were artificially damaged by in-situ precipitation of BaSO4 scale. The coreflood study included injection of the preflush, the treatment fluid and the post-flush system at reservoir temperature of 270 °F and low injection rates to accommodate the low permeability of the formation. It was shown that GLDA based fluid can effectively stimulate the reservoir core samples. The effective mechanism was observed to be wormholing thus increasing rock permeability by over a thousand times. No signs of face dissolution were observed despite slow injection rate at such high temperature; something that was not possible when a fast reacting acid (i.e. HCl) was used under the same conditions. In addition, it was shown that the DTPA based fluid can efficiently improve the rock permeability through matrix cleaning by both Barium and Calcium chelation. In the first treatment test by this fluid system, around 45% of the damaged permeability was recovered. While in the second test, not only BaSO4 scale was dissolved but also the CaCO3 minerals were partly dissolved and the core permeability was significantly increased (Kf/Ki >200). Experimental results bring promising prognosis for field implementation despite expected low injectivity at high downhole temperature. GLDA treatments avoid premature acid spending and face dissolution - common outcomes of HCl- which translate into deeper extent of stimulation. Additionally, in barite damaged wells, DTPA treatment represents an attractive solution for damage reduction and by-passing. Finally, intrinsic properties of chelating agents reduce asset integrity risks, improve operation HSE and simplify flow-back handling.

Petrophysical Core-Based Zonation of An Oil Field In The Bredasdorp Basin South Africa

This study aims to generate rock units based on core permeability and porosity of an oil field in the Bredasdorp Basin offshore South Africa. In this study, we identified and classified lithofacies based on sedimentology reports in conjunction with well logs. Lucia's petrophysical classification method is used to classify rocks into three classes. Results revealed three lithofacies as A(sandstone, coarse to medium-grained), B (fine to medium-grained sandstone), and C (carbonaceous claystone, finely laminated with siltstone). Lithofacies A is the best reservoir quality and corresponds to class 1, while lithofacies B and C correspond to class 2 and 3, which are good and poor reservoir quality rock, respectively. An integrated reservoir zonation for the rocks is based on four different zonation methods (Flow Zone indicator (FZI), Winland r35, Hydraulic conductivity (HC), and Stratigraphy modified Lorenz plot (SMLP)). Four flow zones were identified as high(HFZ), moderate (MFZ), Low (LFZ), and tight (TFZ), respectively. The HFZ is the best reservoir quality composed of a megaporous rock unit, with an average FZI value between 5 to 10µm, and HC from 40 to 120 mD/v3, ranked as very good. The most prolific flow units (HFZ and MFZ zones) form more than 75 % of each well's flow capacities. The TFZ is the most reduced rock quality composed of impervious and nanoporous rock. There appears to be a slight increase of illite in the tight and low zones that block pore throats, thereby decreasing permeability. Therefore, illite has a dominant effect on flow zones. Quartz is the dominant framework grain, and siderite is the dominant cement that affects flow zones. This study has demonstrated a robust approach to delineate flow units in an oilfield. A novel sandstone reservoir zonation classification criteria developed from this study can be applied to other datasets of sandstone reservoirs with confidence.

Effect of permeability and fractures on oil mobilization of unconventional resources during CO2 EOR using nuclear magnetic resonance

CO2 EOR (enhanced oil recovery) will be one of main technologies of enhanced unconventional resources recovery. Understanding effect of permeability and fractures on the oil mobilization of unconventional resources, i.e. tight oil, is crucial during CO2 EOR process. Exposure experiments based on nuclear magnetic resonance (NMR) were used to study the interaction between CO2 and tight oil reservoirs in Chang 8 layer of Ordos Basin at 40 °C and 12 MPa. Effect of permeability and fractures on oil mobilization of exposure experiments were investigated for the different exposure time. The oil was mobilized from matrix to the surface of matrix and the oil recovery increased as the exposure time increased. The final oil recovery increased as the core permeability increased in these exposure experiments. Exposure area increased to 1.75 times by fractures resulting in that oil was mobilized faster in the initial stage of exposure experiment and the final oil recovery increased to 1.19 times from 28.8 to 34.2%. This study shows the quantitative results of effect of permeability and fractures on oil mobilization of unconventional resources during CO2 EOR, which will support CO2 EOR design in Chang 8 layer of Ordos Basin.

ENHANCING THE RESERVOIR PERFORMANCE BY ACCESSING THE RESERVOIR SWEET SPOTS GUIDED BY FAR-FIELD SONIC IMAGING: AN INTEGRATED CASE STUDY FROM THE NORWEGIAN NORTH SEA

The gas present in the Valhall overburden crest area interferes with the seismic data and obscures the fault detection (minor faults). Spatially resolving fractures and fracture network is essential for subsurface understanding and future well placement in this field, and it is a critical input to the dynamic reservoir model. Additionally, mapping the fracture network in poor permeable reservoir formation beyond the wellbore is crucial to identify completion intervals to maximize productivity/injectivity, and hence field value. The well 2/8-F-18 A was drilled on the crest of the Valhall field as a pilot water injector in Lower Hod formation, where core and data analysis formed the foundation for a future potential 11 well development. The well is placed in the southern section of the Valhall crest, and no major faults or strong amplitude features were mapped out in the overburden via surface seismic before drilling. In this case study, an integrated workflow is proposed and tested within the reservoir formation to identify “sweet” (permeable and fractured) zones beyond the wellbore. This is achieved using borehole acoustic data combined with image and ultrasonic imaging to characterize fracture networks beyond the borehole wall. The sonic imaging workflow identifies reflection events from fractures and faults and provides the true dip, azimuth, and location in 3-dimensions. This data is complemented by nuclear magnetic resonance (NMR), dielectric and spectroscopy data to understand reservoir petrophysics. NMR-derived permeability has also been evaluated for identifying high permeable zone in this formation, which primarily focuses on intergranular permeability of the formation a few inches away from the borehole wall. Reservoir textural heterogeneity and fractures beyond the wellbore wall make this method difficult to estimate or enhance the effective permeability estimate. The baseline assumption for the NMR permeability estimation is also not valid in Hod formation; the Timur and SDR equation needs significant change to match core permeability. Hence, the primary aim is to identify a fracture network that will help support water injection and maximize hydrocarbons production through them. The goal is to establish a workflow from the learnings of this study, performed on the pilot well, validate its findings with the near-field data (core, imaging, and ultrasonic), and optimize it if needed (described in the methodology section). The developed workflow is then intended to be used to optimize the placement of future wells. The results achieved from the integrated workflow identified a key fault and mapped it approximately 23 meters away on each side of the borehole. It also captures acoustic anomalies (high amplitudes), validated based on near-field data, resulting from a fracture network potentially filled with hydrocarbons. The final results show the sub-seismic resolution of the fracture and fault network not visible on surface seismic due to the gas cloud above the reservoir and frequency effect on the surface seismic when compared to borehole sonic data. Evidently enhancing the blurred surface image, which helps enhance the structural and dynamic model of the reservoir.

Laboratory Investigation of Permeability Impairment Caused by Asphaltene Precipitation during Screening for Gas-Injection Enhanced Oil Recovery and Pressure Change in a Major Gulf of Mexico Field

Summary As part of studying miscible gas injection (GI) in a major field within the Green Canyon protraction area in the Gulf of Mexico (GOM), asphaltene-formation risk was identified as a key factor affecting a potential GI project. The industry has not conducted many experiments to quantify the effect of asphaltenes on reservoir and well performance under GI conditions. In this paper we discuss a novel laboratory test for evaluating the asphaltene effect on permeability. The goals of the study were to define the asphaltene-precipitation envelope using blends of reservoir fluid and injection gas, and measure permeability reduction caused by asphaltene precipitation in a core under GI. To properly analyze the effect of GI, a suite of fluid-characterization studies was conducted, including restored-oil samples, compositional analysis, constant composition expansion (CCE), and differential vaporization. Miscibility conditions were defined through slimtube-displacement tests. Gas solubility was determined through swelling tests complemented by asphaltene-onset-pressure (AOP) testing. The unique procedure was developed to estimate the effect of asphaltene deposition on core permeability. The 1-ft-long core was saturated with the live-oil and GI mixture at a pressure greater than the AOP, and then pressure was depleted to a pressure slightly greater than the bubblepoint. Several cycles of charging and depletion were conducted to mimic continuous flow of oil along the path of injected gas and thereby to observe the accumulation of asphaltene on the rock surface. The test results indicated that during this cyclic asphaltene-deposition process, the core permeability to the live mixture decreased in the first few cycles but appeared to stabilize after Cycle 5. The deposited asphaltenes were analyzed further through environmental scanning electron microscopy (ESEM), and their deposition was confirmed by mass balance before and after the tests. Finally, a relationship was established between permeability reduction and asphaltene precipitation. The results from the asphaltene-deposition experiment show that for the sample, fluids, and conditions used, permeability is impaired as asphaltene flocculates and begins to coat the grain surfaces. This impairment reaches a plateau at approximately 40% of the initial permeability. Distribution of asphaltene along the core was measured at the end by segmenting the core and conducting solvent extraction on each segment. Our recommendation is numerical modeling of these test results and using this model to forecast the magnitude of the permeability impairment in a reservoir setting during miscible GI.

Partitioned Permeability Diagram: an innovative way to estimate Fault Zones hydraulics.

<p>Understanding the impact of fault zones on reservoir trap properties is a major challenge for a variety of geological ressources applications. Fault zones in cohesive rocks are complex structures, composed of 3 components: rock matrix, damage zone fractures and fault core rock. Despite the diversity of existing methods to estimate fault zone permeability/drain properties, up to date none of them integrate simultaneously the 3 components of fracture, fault core and matrix permeability, neither their evolution with time. We present a ternary plot that characterizes the fault zones permeability as well as their drainage properties. The ternary plot aims at (i) characterizing the fault zone permeability between the three vertices of matrix, fractures and fault core permeability ; and at (ii) defining the drain properties among 4 possible hydraulic system: (I) good horizontal and vertical, fault-perpendicular and -parallel; (II) moderate parallel fluid pathway; (III) good parallel fault-core and (IV) good parallel fractures. The ternary plot method is valid for 3 and 2 components fault zones. The application to the Castellas Fault case study show the simplicity and efficiency of the plot for studying underground and/or fossil, simple or polyphase faults in reservoirs with complete or limited permeability data.</p>

Pore-Scale Investigation on the Plugging Behavior of Submicron-Sized Microspheres for Heterogeneous Porous Media with Higher Permeability

Reservoir heterogeneity is regarded as one of the main reasons leading to low oil recovery for both conventional and unconventional reservoirs. High-permeability layers or fractures could result in ineffective water or gas injection and generate nonuniform profile. Polymer microspheres have been widely applied for the conformance control to overcome the bypass of injected fluids and improve the sweep efficiency. For the purpose of examining the plugging performance of submicron-sized microspheres in high-permeability porous media, systematic investigations were implemented incorporating macroscale blocking rate tests using core samples and pore-scale water migration analysis via nuclear magnetic resonance (NMR). Experimental results indicate that microsphere particle size dominates the plugging performance among three studied factors and core permeability has the least influence on the plugging performance. Subsequently, microsphere flooding was conducted to investigate its oil recovery capability. Different oil recovery behaviors were observed for cores with different permeability. For cores with lower permeability, oil recovery increased stepwise with microsphere injection whereas for higher permeability cores oil recovery rapidly increased and reached a plateau. This experimental work provides a better understanding on the plugging behavior of microspheres and could be employed as a reference for screening and optimizing the microsphere flooding process for profile control in heterogeneous reservoirs.