Produced water chemical compositional data are collected from a carbonate reservoir which had been flooded by North Seawater for more than 20 years, so there is an opportunity to analyse the large amount of produced water data collected, understand the brine/brine and brine/rock interactions and explore the impact factors behind them. In some publications, core flood experimental tests were performed with chalk cores or carbonate columns in order to make an understanding of possible chemical reactions occurring triggered by injected water with different composition (Seawater, low salinity water or any other brine). However, most of the time the laboratory conditions where core flooding experiments are implemented cannot fully simulate the real reservoir conditions. Therefore, in this study, with the help of the valuable produced water dataset and some basic reservoir properties, a one-dimensional reactive transport model is developed to identify what in situ reactions were taking place in the carbonate reservoir triggered by seawater injection.
From the perspective of reservoir mineralogy, calcite, as the dominant mineral in the carbonate reservoir, is relatively more chemically reactive than quartz and feldspar which are usually found in sandstone. Whether calcite is initially and dominantly present in the carbonate reservoir rock is dissolved under seawater flooding or not is the first key issue we focused on. The effects of calcite dissolution on the sulphate scaling reactions due to incompatible brine mixing and the potential occurrence of carbonate mineral precipitation induced by calcite dissolution are investigated and discussed in detail. The comparison of simulation results from the isothermal model and the non-isothermal model show the important role of temperature during geochemical processes. The partitioning of CO2 from the hydrocarbon phase into injected brine was considered through calculation of the composition of reacted seawater equilibrated with the CO2 gas phase with fixed partial pressure (equivalent with CO2 content), then subsequently the impact of CO2 interactions on the calcite, dolomite and huntite mineral reactions are studied and explained. We also use calculation results from the model to match the observed field data to demonstrate the possibility of ion exchange occurring in the chalk reservoir.
Zhang, Lufeng (China University of Petroleum) | Zhou, Fujian (China University of Petroleum) | Wang, Jie (China University of Petroleum) | Wang, Jin (China University of Petroleum) | Mou, Jianye (China University of Petroleum) | Zhang, Shicheng (China University of Petroleum)
ABSTRACT: Acid propped fracturing is a valid stimulation technique applied in deep carbonate reservoirs and its effect mainly depends on the conductivity. However, short-term conductivity experimental data used in existing acid propped fracturing design may not be directly applicable to real case. Aiming at this problem, this paper investigates impacts of acid-rock contact time, acid etched fracture creep, proppant size and concentration on the long-term conductivity. The study shows that the acid propped fracture retained enough conductivity under high closure stress. Gelled acid fracture conductivity increases with the longer time until it reached the upper limit when the contact time is 60 minutes. The long-term conductivity experiments show that conductivity decreased sharply in the 48 hours and underwent a gradual decline from 48 hours to 96 hours followed by the steady state after 120 hours. The ideal combination of proppant size and concentration are optimized at different stress level. An acid propped fracture conductivity correlation was also developed for calculating the conductivity. This study provides an insight of optimizing acid propped fracturing design and predicting well performance.
As significant domains of oil and gas exploration and development, carbonate reservoirs constitute almost 60% of the world's remaining oil and gas. Acid fracturing, as a conventional and effective stimulation method, has been widely used in carbonate formation (Amirhossein and Maysam, 2016). However, due to serious acid leakage and rapid acid-rock reaction speed resulting from high temperature and closure stress in deep well, the length of effective acid etched fracture is limited and the effective duration of acid etched fracture is short (Li Y et al., 2009; Suleimenova A et al., 2016;). Consequently, uniting the deep penetration of acidizing with proppant fracturing is a natural progression toward great effective stimulation of deep carbonate reservoirs. Acid propped fracturing, combining the advantages of propped fracturing and acid fracturing, is the technology that can not only readily carry proppant but also react with the carbonate formation to eliminate the formation damage. It also can connect natural fracture, maximizing the drainage area and the stimulation reservoir volume (SRV).
Tariq, Zeeshan (King Fahd University of Petroleum & Minerals) | Abdulraheem, Abdulazeez (King Fahd University of Petroleum & Minerals) | Elkatatny, Salaheldin (King Fahd University of Petroleum & Minerals) | Mahmoud, Mohamed (King Fahd University of Petroleum & Minerals) | Muqtadir, Arqam (King Fahd University of Petroleum & Minerals) | Murtaza, Mobeen (King Fahd University of Petroleum & Minerals)
In a quest to reduce the greenhouse gasses, geologic sequestration of carbon dioxide (CO2) in an underground hydrocarbon rock formation or aquifer is one of the most promising alternative to reduce the amount of CO2 release in an open environment. However, long-term storage of CO2 effects the geomechanical and geochemical properties of the host rock. In carbonate aquifers, water dissolves the injected CO2 gas forming carbonic acid which has the tendency to dissolve calcium compounds present in the formation. The dissolution of calcium is particularly worrying since it contributes to the matrix of the rock. Thus, the mechanical properties of the rock are altered, which left unattended could result and in compaction of the formation and surface subsidence.
This paper aims to study the degradation of the petrophysical and mechanical properties of two types of rocks namely limestone and sandstone due to the storage of supercritical CO2 for desired amount of time. Supercritical CO2 has low viscosity but high density and has ability to store in large amount within the same space and with the high pumping efficiency. Two different carbonate rocks and one sandstone rock were exposed to a CO2-brine solution at a pressure of 1200 psi and at 120 °C for durations ranging from 10 to 120 days. The mechanical properties were then examined by both static and dynamic mechanical tests along with the routine core analysis (RCA).
Results showed that long term CO2 storage affected the mechanical, acoustic and petrophysical parameters of rocks examined in this study, viz., Khuff limestone, Berea Sandstone, and ordinary limestone. The duration of solubility time brine-CO2-rock has a considerable impact on the petrophysical and mechanical parameters of the rock samples. Outcomes of this study also shows that the rock mechanical and petrophysical properties significantly affected when CO2 store for the longer period of time. CO2, rock, and brine interaction is dependent on time consequently the rock mechanical and petrophysical parameters changes are also time dependent. The potential candidate found for geological sequestration of CO2 studied is limestone because of its minimal rock properties altered.
Release of CO2 gas in the environment is one of the main concern and reason for the rise in the global warming because CO2 has the tendency to trap heat. Although about half of the greenhouse gasses are absorbed naturally (into deeper seas), the rest stays in the Earth's atmosphere for centuries.
Patacchini, Leonardo (Abu Dhabi Marine Operating Company) | Mohmed, Farzeen (Abu Dhabi Marine Operating Company) | Lavenu, Arthur P. C. (Abu Dhabi Marine Operating Company) | Ouzzane, Djamel (Abu Dhabi Marine Operating Company) | Hinkley, Richard (Halliburton) | Crockett, Steven (Halliburton) | Bedewi, Mahmoud (Halliburton)
The classic method for initializing reservoir simulation models in the presence of a transition zone, based on primary drainage capillary-gravity equilibrium, is extended to account for partial reimbibition post oil migration. This tackles situations where structural events, such as trap tilting or caprock leakage, caused the current free-water level (FWL) to rise above deeper paleo-contacts. A preliminary primary drainage initialization is performed with zero capillary pressure at the paleo (or deepest historical) FWL, to obtain a minimum historical water saturation distribution. From a capillary pressure hysteresis model, it is then possible to determine the appropriate imbibition scanning curve for each gridblock, which are used to perform a second initialization with zero capillary pressure at the current FWL. With the proposed method, log-derived saturation profiles can be honored using a physically meaningful capillary pressure model. Furthermore, when relative permeability hysteresis is active, it is possible as a byproduct of the initialization to assign the correct scanning curves at time zero to each gridblock, which ensures that initial phase mobilities (hence reservoir productivity) and residual oil saturation (hence recoverable oil to waterflood) are modeled correctly. This is demonstrated with a synthetic vertical 1D model. The method was implemented in a commercial reservoir simulator to support modeling work for a giant undeveloped carbonate reservoir, where available data suggest that more than 3/4 of the initial oil in place could be located between the current FWL and a dome-shaped paleo-FWL. This work is used as a case study to illustrate the elegance of the proposed method in the presence of multiple (or tilted) paleo-FWLs, as only one set of capillary pressure curves per dynamic rock-type is required to honor the complex logderived saturation distribution.
Periere, Matthieu Deville de (Badley Ashton and Associates Ltd.) | Foote, Alexander (Badley Ashton and Associates Ltd.) | Bertouche, Meriem (Badley Ashton and Associates Ltd.) | Shah, Razza (Al Hosn Gas.) | al-Darmaki, Fatima (Al Hosn Gas.) | Ishaq, Wala bin (Al Hosn Gas.)
The Lower Arab D Member (Kimmeridgian) in onshore UAE is typically characterised by a thick succession of homogeneous mudstones with local cm-scale interbedded bivalve-rich floatstones, which are thought to have been deposited in a low-energy mid-ramp setting. This sedimentological unit is located at the base of a sour gas reservoir that includes the oolitic grainstones of the Upper Arab D Member. The pore system in these micritic deposits is dominated by matrix-hosted microporosity, along with open to partially cemented fractures, primary intraparticle macropores and rare biomoulds in the shell beds, hence a poor to very good porosity and extremely poor to rarely excellent permeability. Variations in porosity and permeability values appear to be strongly related to variations in the micritic fabric: both porosity and permeability increase when the micritic fabric evolves from anhedral compact with coalescent intercrystalline contacts (associated with very little and poorly connected micropores) to subrounded with facial to subpunctic intercrystalline contacts (with locally well-developed micropores). Micritic fabrics also clearly impact the elastic properties of the rock. Through analysis of elastic moduli calculated from standard density, and shear/compressional sonic wireline logs, the relationship between micritic fabric, porosity, permeability and geomechanical properties has been explored.
The Solan oil field is located offshore in the hostile north Atlantic ~135 kilometres west of the Shetland Isles, UK, in ~135 metre water depth. The field commenced production in 2016. The relatively remote field was developed by four subsea wells tied back to a single slim jacket with a minimum facility topsides. The development includes several innovative features such as full automation, which enables full remote control from an onshore control room in Aberdeen, UK, but strikingly, a world development first involving the installation of an independent steel subsea oil storage tank (SOST) located ~300 metres from the platform. The concept selection, design, fabrication, installation and operation of this novel feature are the subject of this paper.
The concept selection of the SOST was driven by several factors including HSE, life cycle cost and operational considerations for this modest sized development in a harsh marine setting. An obvious competitor concept is a subsea well and FPSO alternate; the pros and cons of each approach are compared, using actual field performance now seen versus assumption at the time of concept select.
The multiple-compartment SOST is capable of holding almost 300,000 barrels of stabilised oil; it has an in-air weight of ~10,100 tonnes and internal dimensions of 45m x 45m x 25m. The oil is offloaded to a shuttle tanker through a single anchor loading (SAL™) system with the offloading hose stored on the seabed, which is picked up using a pennant line. Oil export to the tanker is driven by hydrostatic displacement by treated seawater from the topsides. This operation is conducted while still producing oil to the SOST. The tank design has novel features for installation, oil-water interface management and corrosion monitoring and subsea inspection.
The tank's detailed design and construction phase involved some significant changes as the structural and fatigue life issues were fully analysed and implemented. The installation required significant pre-planning with the use of a very large lifting sling arrangement and a smart air venting and water ballasting system, to then land its eight skirt piles to a tight tolerance on the seabed.
Following a commissioning program and trial tanker offload using treated seawater alone, over the past year the SOST has now successfully undergone numerous oil fill and tanker offload operations. There have been learnings regarding the offloading operation but to date the concept has worked in a manner very close to expectation with a full tank offload achieved in less than ~36 hours. The paper closes with a review of how the concept could be improved further considering the experiences now gained from both the project and operational phases.
Poulsen, Morten (Danish Technological Institute Oil & Gas) | Sanders, Peter Frank (Danish Technological Institute Oil & Gas) | Thomsen, Uffe Sognstrup (Danish Technological Institute Oil & Gas) | Lundgaard, Thomas (Danish Technological Institute Oil & Gas)
In severe MIC cases, the system may even need to be replaced, sometimes with corrosion resistant alloys, with marked economic consequences to operators. The threat of MIC has traditionally been very difficult to assess due to its rapid, localized, nature and due to the challenges of getting reliable information about microbial communities from system samples. Methods: Recent advances in molecular microbiology technologies, particularly with respect to next generation sequencing technologies and quantitative PCR assays targeting functional and phylogenetic marker genes, have now made it possible to reliably identify and quantify a range of oilfield MICrelated microorganisms. Results and Conclusions: Through case studies, this paper demonstrates how these molecular microbiology technologies can be used for monitoring, diagnosing and managing MIC on a routine basis focusing on key MIC indicator organisms and applying new approaches to interpret the MIC threat from the derived data. This paper furthermore suggests how MIC assessments can be integrated into existing corrosion management programs to target and tailor mitigation actions, minimizing the overall risk related to MIC. Novel/Additive Information: These new advanced molecular microbiology tools, if properly integrated in corrosion management programs, hold potential for improving asset protection and cost savings for oilfield operators.
Supercritical CO2 flooding in unconventional tight sandstone reservoir is characterised as the complex changeable and irregular effects on the properties of crude oil and the system of pore-throat-fracture in formation. In the light of the above problems, being aimed at a typical unconventional tight sandstone reservoir, such a new thinking and methods as the methods of combining multiple experiment and test measurements, the methods from qualitative analysis to quantitative evaluation, the methods from phenomenon observation to essence revelation, and the methods from data statistics and analyzing to representation model setting up are putforwarded and used to study those problems comprehensively. In the CO2 displacement process, asphaltene, resin, and paraffin are easily to be separated out from crude oil. Meanwhile, pore throats in rock formation can be blocked by the precipitate. In addition, when CO2was dissolved into formation water, PH value of the formation water was changed to be weakly acidic which has a certain dissolution for part of mineral composition of formation core, increasing the pore volume of reservoir. This article will launch the quantitative evaluation of the effects on these two factors on the pore throat system. By changing the experimental conditions to determine the amount of asphalt component in the core during whole experiment, then using the advanced and reasonable test technology to analysis the result after the experiment. The results showed that the recovery ratio of kerosene and oil increased with changing the experimental conditions. The recovery of kerosene raised with increasing pressure and volume. The increased range permeability of nature core rised the highest (6.7%) when the pressure was 26 MPa; The main reason for this phenomenon is acidification in the system of pore-throat-fracture. Less than 26 Mpa, the recovery of kerosene raised with increasing pressure. The amount of asphaltene deposition reached the greatest (51.3%) when the pressure was 29 Mpa. The decreased range of core permeability reduced the lowest (31%) when the pressure was 29 Mpa. The amount of asphaltene deposition and the decreased range of core permeability increased first and then reduced with increasing injection pressure and injection volume of CO2.
Ovcharenko, Y. (OOO Gazpromneft NTC) | Lukin, S. (OOO Gazpromneft NTC) | Tatur, O. (OOO Gazpromneft NTC) | Kalinin, O. (OOO Gazpromneft NTC) | Kolesnikov, D. (OOO Gazpromneft NTC) | Esipov, S. (OOO Gazpromneft NTC) | Zhukov, V. (OOO Gazpromneft NTC) | Demin, V. (OOO Gazpromneft-Angara) | Volokitin, Y. (Salym Petroleum Development N. V.) | Sednev, A. (Salym Petroleum Development N. V.) | Podberezny, M. (Salym Petroleum Development N. V.)
Work is devoted to construction 3D Geomechanics model for Achimov Formation for one of the West Siberia oilfield. The model is performed for monitoring and control field throughout the cycle of its life – start from drilling process (recommendation for optimization well trajectory and well design to exclude drilling risks) and during oilfield development (monitoring the development process to take account of changes in the stress state of the oilfield, its influence on the hydraulic fracture growth and hydrocarbon production processes). Oilfield, which are currently introduced in the development, characterize by increasingly complex geology and, consequently, require more sophisticated technological solutions for both the construction of wells and the development process, which involves the need to build complex 3D geological and geomechanical models.
As a result of the work was calculated current stress state on the field, taking into account the effects of faults. Special attention was paid to the process of mapping of faults and low-amplitude tectonic dislocation. For this purpose used inversion stress model, including simulation of deformations and displacements arising under the action of tectonic driver. This model allows to select the tectonic dislocation, the scale of which is significantly smaller than the resolution of seismic.
Based on the results of the verification of geomechanical model and sensitivity analysis to the source data, formulated the basic methodological approaches for building and testing models of geomechanical properties was done. During the work was made a forecast borehole stability for horizontal wells, create a map of faults, found the relationship between the faults parameters and their impact on the stress changes in the area of interest, assessed the impact of changes in reservoir pressure during field development on the stress orientation, predicted direction of hydraulic fracture and formed recommendations on hydraulic fracturing design taking into account possible variations in the stress state of the sector of modeling.
During hydraulic fracture propagation three regions may be identified from the pressure response referred to as: 1) near-well, that extends tens of inches, 2) mid-field, that extends tens of feet and 3) far-field, that extends hundreds of feet from the wellbore. Each region can experience simple, tortuous, and complex fracture behavior creating unique pressure signatures. It has been observed that complex fractures with extended fracture storage can result from hydraulic fracture stimulation in highly deviated and horizontal wells. Complexity is created as a result of induced hydraulic fractures turning and twisting as they exit the wellbore in the near-well region, propagating into the mid-field region, and then re-orienting in the direction of principal stresses in the far-field. This results in anomalously high apparent net pressures as evident by increased ISIP's and rapidly declining pressures that dissipate minutes after shut-in.
This paper presents minifrac and post-job pressure matching case studies that identify and describe mid-field fracture complexity (MFC), or extended wellbore pressure storage. The pressure behavior supports complex fracture propagation, high fracturing pressures and pressure fall-off responses typically observed in horizontal shale wells. High apparent fracturing stress gradients are often seen that are much greater than the over-burden stress-gradients. Although suggestive, these high stress gradients are not indicative of horizontal fractures in the far-field. Uncharacteristically high MFC is also not necessarily related to fracture complexity in the far-field. A methodology is presented that identifies the "actual" ISIP which allows for in-situ stress calibration, true net pressure identification, proper minifrac interpretation and an improved fracture treatment design.
Rapidly declining pressure during a shut-in as a result of MFC resembles pressure dependent fluid loss and often is misinterpreted as such. However, the pressure response is a result of extended fracture storage and energy dissipation in the mid-field region, which can result in multiple closure signatures. Multiple closure events are indicative of complex fracture network behavior as a result of stress anisotropy and creation of multiple non-planar fractures in the mid-field region. Additionally, hydraulically induced secondary fractures perpendicular to the maximum horizontal stress can provide insight into stress anisotropy. Identifying and incorporating MFC into pressure interpretation analyses will enhance fracture treatment design and post-job pressure matching providing a systematic methodology for designing and analyzing horizontal shale fracture treatments. Information regarding MFC is critical in interpreting fracture treatment pressure responses and optimizing fracture treatment designs in horizontal wells, including well spacing and fracture interference.