scholarly journals Reservoir Productivity Analysis of Intercalated Limestone and Anhydrite Beds in Zagros Folded Belt, Kurdistan Region of Iraq

2020 ◽  
Vol 5 (1) ◽  
pp. 1-15
Author(s):  
Fraidoon Rashid
Keyword(s):  
Early Jurassic ◽  
Carbonate Reservoir ◽  
Fluid Distribution ◽  
Log Analysis ◽  
Productivity Analysis ◽  
Core Samples ◽  
Heterogeneous Rocks ◽  
Tight Carbonate ◽  
Jurassic Rock ◽  
Mud Logging

The Early Jurassic rock of Alan Formation in Barda Rash field has been examined using petrophysical wireline log analysis, drilling stem test, mud logging reports, drilling cutting and core samples for evaluation of reservoir potentiality and fluid production throughout heterogeneous rocks intervals in three exploration and appraisal wells. The Alan Formation consists of intercalation of light, chalky and argillaceous limestone beds with shale layers in the upper part and dominantly anhydrite layers from the middle to the lower parts of the formation. Qualitatively, weak oil shows of light brown to dark brown and blackish heavy oil have been observed while drilling. Furthermore, light brown trace oil has been recorded in the fracture surfaces of the core samples. The wireline log analysis provided an overestimated result for the hydrocarbon bearing interval identification and fluid movability index as the anhydrite layers confused the fluid distribution detection in the drilled interval. However, the combined results achieved from the mud logging reports and drilling stem tests were operated within the drilled intervals shown a limited productivity levels from the limestone beds of the Early Jurassic Alan Formation.  The oil production from the studied interval does not exceed 10% and the entire production rates were composed of formation water with a trace amount of gases. As a result, the Early Jurassic Alan Formation can be considered as a tight carbonate reservoir rocks in the Barda Rash field.

Using Logging and Seismic Data to Identify Boundaries Between Different OWC Units in a Deepwater Carbonate Reservoirs

2021 ◽  
Author(s):  
Kangxu Ren ◽  
Junfeng Zhao ◽  
Jian Zhao ◽  
Xilong Sun
Keyword(s):  
Seismic Data ◽  
Carbonate Rocks ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Sedimentary Process ◽  
Core Samples ◽  
Tight Carbonate ◽  
Porosity And Permeability ◽  
Seismic Sections ◽  
Parameters Inversion

Abstract At least three very different oil-water contacts (OWC) encountered in the deepwater, huge anticline, pre-salt carbonate reservoirs of X oilfield, Santos Basin, Brazil. The boundaries identification between different OWC units was very important to help calculating the reserves in place, which was the core factor for the development campaign. Based on analysis of wells pressure interference testing data, and interpretation of tight intervals in boreholes, predicating the pre-salt distribution of igneous rocks, intrusion baked aureoles, the silicification and the high GR carbonate rocks, the viewpoint of boundaries developed between different OWC sub-units in the lower parts of this complex carbonate reservoirs had been better understood. Core samples, logging curves, including conventional logging and other special types such as NMR, UBI and ECS, as well as the multi-parameters inversion seismic data, were adopted to confirm the tight intervals in boreholes and to predicate the possible divided boundaries between wells. In the X oilfield, hundreds of meters pre-salt carbonate reservoir had been confirmed to be laterally connected, i.e., the connected intervals including almost the whole Barra Velha Formation and/or the main parts of the Itapema Formation. However, in the middle and/or the lower sections of pre-salt target layers, the situation changed because there developed many complicated tight bodies, which were formed by intrusive diabase dykes and/or sills and the tight carbonate rocks. Many pre-salt inner-layers diabases in X oilfield had very low porosity and permeability. The tight carbonate rocks mostly developed either during early sedimentary process or by latter intrusion metamorphism and/or silicification. Tight bodies were firstly identified in drilled wells with the help of core samples and logging curves. Then, the continuous boundary were discerned on inversion seismic sections marked by wells. This paper showed the idea of coupling the different OWC units in a deepwater pre-salt carbonate play with complicated tight bodies. With the marking of wells, spatial distributions of tight layers were successfully discerned and predicated on inversion seismic sections.

Enhanced and Rock Typing-Based Reservoir Characterization of the Palaeocene Harash Carbonate Reservoir-Zelten Field-Sirte Basin-Libya

2021 ◽  
Author(s):  
Mohamed Masoud ◽  
W. Scott Meddaugh ◽  
Masoud Eljaroshi ◽  
Khaled Elghanduri
Keyword(s):  
Rock Type ◽  
Carbonate Reservoir ◽  
Classification Model ◽  
Reservoir Rocks ◽  
The Core ◽  
Core Samples ◽  
Rock Types ◽  
Rock Typing ◽  
Open Hole ◽  
Type Classification

Abstract The Harash Formation was previously known as the Ruaga A and is considered to be one of the most productive reservoirs in the Zelten field in terms of reservoir quality, areal extent, and hydrocarbon quantity. To date, nearly 70 wells were drilled targeting the Harash reservoir. A few wells initially naturally produced but most had to be stimulated which reflected the field drilling and development plan. The Harash reservoir rock typing identification was essential in understanding the reservoir geology implementation of reservoir development drilling program, the construction of representative reservoir models, hydrocarbons volumetric calculations, and historical pressure-production matching in the flow modelling processes. The objectives of this study are to predict the permeability at un-cored wells and unsampled locations, to classify the reservoir rocks into main rock typing, and to build robust reservoir properties models in which static petrophysical properties and fluid properties are assigned for identified rock type and assessed the existed vertical and lateral heterogeneity within the Palaeocene Harash carbonate reservoir. Initially, an objective-based workflow was developed by generating a training dataset from open hole logs and core samples which were conventionally and specially analyzed of six wells. The developed dataset was used to predict permeability at cored wells through a K-mod model that applies Neural Network Analysis (NNA) and Declustring (DC) algorithms to generate representative permeability and electro-facies. Equal statistical weights were given to log responses without analytical supervision taking into account the significant log response variations. The core data was grouped on petrophysical basis to compute pore throat size aiming at deriving and enlarging the interpretation process from the core to log domain using Indexation and Probabilities of Self-Organized Maps (IPSOM) classification model to develop a reliable representation of rock type classification at the well scale. Permeability and rock typing derived from the open-hole logs and core samples analysis are the main K-mod and IPSOM classification model outputs. The results were propagated to more than 70 un-cored wells. Rock typing techniques were also conducted to classify the Harash reservoir rocks in a consistent manner. Depositional rock typing using a stratigraphic modified Lorenz plot and electro-facies suggest three different rock types that are probably linked to three flow zones. The defined rock types are dominated by specifc reservoir parameters. Electro-facies enables subdivision of the formation into petrophysical groups in which properties were assigned to and were characterized by dynamic behavior and the rock-fluid interaction. Capillary pressure and relative permeability data proved the complexity in rock capillarity. Subsequently, Swc is really rock typing dependent. The use of a consistent representative petrophysical rock type classification led to a significant improvement of geological and flow models.

Needles in the Pay Stack ADNOC Exploring Tight-Oil Rock, Triples Production In First Pilot

2021 ◽  
Vol 73 (01) ◽  
pp. 20-22
Author(s):  
Trent Jacobs
Keyword(s):  
Carbonate Reservoir ◽  
Reservoir Rock ◽  
Abu Dhabi ◽  
Data Set ◽  
Slowing Down ◽  
Tight Carbonate ◽  
Potential Impact ◽  
Carbonate Formations ◽  
Oil Company ◽  
Term Data

In the midst of an industry downturn last year, the Abu Dhabi National Oil Company (ADNOC) reached a new oil production ceiling of 4 million B/D. The UAE’s largest producer has no intentions of slowing down. By decade’s end, ADNOC expects to have raised its maximum daily output by another million barrels. To cross that milestone, the company has set its sights on mastering the tight, thin, and unconventional formations that dot the UAE’s subsurface landscape. One of the places where such developments are hoped to unfold soon is known as Field Q. Found in southeastern Abu Dhabi, Field Q sits above a tight carbonate reservoir that holds an estimated 600 million bbl of oil. But with a permeability ranging from 1 to 3 millidarcy and poor vertical communication, the reservoir and its barrels have proven difficult to cultivate economically - until recently. ADNOC has published new details of its first onshore pilot of a “fishbone stimulation” that involved using more than a hundred hollow needles to pierce as far as 40 ft into the reservoir rock. The additional drainage netted by the fishbone needles boosted production threefold in the test well, as compared with its traditionally completed neighbors on the same pad. ADNOC ran the pilot in the summer of 2019 and by the end of the year saw enough production data to launch a wider 10-well pilot that remains underway. Based on a longer-term data set from these wells, the company will decide whether to leap into a fieldwide deployment of the niche completions technology. In the meantime, the petrotechnical team in charge of the test projects have issued roundly positive reviews of the fishbone technique in two recently presented technical papers (SPE 202636; SPE 203086) from the Abu Dhabi International Petroleum Exhibition & Conference (ADIPEC). “There is a chance that the fishbone-stimulated wells can avoid the drilling of multiple wells targeting different sublayers in the same zone,” said Rama Rao Rachapudi, listing one of several of the technology’s advantages over other approaches that were considered. The senior petroleum engineer with ADNOC, who is one of several authors of the papers that cover both the drilling and completions aspects of the pilot, shared during ADIPEC that his onshore team found motivation to test the technology after bringing in a batch of dis-mal appraisal wells. The fishbone system, also known as multilateral jetting stimulation technology, has been a specialized application ever since it was introduced just over a decade ago. Underscoring the potential impact of the current round of pilots on the technology’s adoption rate, ADNOC noted there were only around 30 worldwide fishbone deployments prior to this project. Most of those have been in the Middle East’s naturally fractured and layered carbonate formations - just like those of Field Q.

Using rock physics models to validate rock composition from multimineral log analysis

Geophysics ◽  
2021 ◽  
pp. 1-69
Author(s):  
Liwei Cheng ◽  
Manika Prasad ◽  
Reinaldo J. Michelena ◽  
Ali Tura ◽  
Shamima Akther ◽  
...  
Keyword(s):  
Quality Control ◽  
Reservoir Characterization ◽  
Rock Physics ◽  
Inequality Constraint ◽  
Effective Medium ◽  
Carbonate Reservoir ◽  
Log Analysis ◽  
Evaluation Tool ◽  
Rock Composition ◽  
Effective Medium Models

Multimineral log analysis is a quantitative formation evaluation tool for geological and petrophysical reservoir characterization. Rock composition can be estimated by solving equations that relate log measurements to the petrophysical endpoints of minerals and fluids. Due to errors in log data and uncertainties in petrophysical endpoints of constituents, we propose using effective medium models from rock physics as additional independent information to validate or constrain the results. In this paper, we examine the Voigt-Reuss (VR) bound model, self-consistent approximation (SCA), and differential effective medium (DEM). The VR bound model provides the first-order quality control of multimineral results. We first show a conventional carbonate reservoir study with intervals where the predicted effective medium models from multimineral results are inconsistent with the measured elastic properties. We use the VR bound model as an inequality constraint in multimineral analysis for plausible alternative solutions. SCA and DEM models provide good estimates in low porosity intervals and imply geological information for the porous intervals. Then, we show a field case of the Bakken and Three Forks formations. A linear interpolation of the VR bound model helps validate multimineral results and approximate the elastic moduli of clay. There are two major advantages to use our new method (a) rock physics effective medium models provide independent quality control of petrophysical multimineral results, and (b) multimineral information leads to realistic rock physics models.

Using Advance Acid Fracturing Design to Increase the Production Efficiency in a HPHT Reservoir: A Success Story from Southern Mexico

2021 ◽  
Author(s):  
Frank Figueroa ◽  
Gustavo Mejías ◽  
José Frías ◽  
Bonifacio Brito ◽  
Diana Velázquez ◽  
...  
Keyword(s):  
High Temperature ◽  
Laboratory Tests ◽  
Reaction Rates ◽  
Gas Production ◽  
Carbonate Reservoir ◽  
Fluid Distribution ◽  
Acid Etching ◽  
Southern Mexico ◽  
Acid Fracturing ◽  
Fluid Systems

Abstract Enhanced hydrocarbon production in a high-pressure/high-temperature (HP/HT) carbonate reservoir, involves generating highly conductive channels using efficient diversion techniques and custom-designed acid-based fluid systems. Advanced stimulation design includes injection of different reactive fluids, which involves challenges associated with controlling fluid leak-off, implementing optimal diversion techniques, controlling acid reaction rates to withstand high-temperature conditions, and designing appropriate pumping schedules to increase well productivity and sustainability of its production through efficient acid etching and uniform fluid distribution in the pay zone. Laboratory tests such as rock mineralogy, acid etching on core samples and solubility tests on formation cuttings were performed to confirm rock dissolving capability, and to identify stimulation fluids that could generate optimal fracture lengths and maximus etching in the zone of interest while corrosion test was run to ensure corrosion control at HT conditions. After analyzing laboratory tests results, acid fluid systems were selected together with a self-crosslinking acid system for its diversion properties. In addition, customized pumping schedule was constructed using acid fracturing and diverting simulators and based on optimal conductivity/productivity results fluid stages number and sequence, flow rates and acid volumes were selected. The engineered acid treatment generated a network of conductive fractures that resulted in a significant improvement over initial production rate. Diverting agent efficiency was observed during pumping treatment by a 1,300 psi increase in surface pressures when the diverting agent entered the formation. Oil production increased from 648.7 to 3105.89 BPD, and gas production increased from 4.9 to 26.92 MMSCFD. This success results demonstrates that engineering design coupled with laboratory tailor fluids designs, integrated with a flawless execution, are the key to a successful stimulation. This paper describes the details of acidizing technique, treatment design and lessons learned during execution and results.

CONTROLS ON FRACTURE FLOW POTENTIAL IN A TIGHT CARBONATE RESERVOIR: SAYINDERE FORMATION (CAMPANIAN), WEST ADIYAMAN BASIN, SE TURKEY

2019 ◽  
Vol 42 (2) ◽  
pp. 207-228
Author(s):  
S. I. Ozkaya ◽  
T. Dölek ◽  
K. Yapan ◽  
B. Alper Durukan
Keyword(s):  
Carbonate Reservoir ◽  
Fracture Flow ◽  
Flow Potential ◽  
Tight Carbonate ◽  
Se Turkey
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