scholarly journals Experiment of Carbonate Dissolution: Implication for High Quality Carbonate Reservoir Formation in Deep and Ultradeep Basins

Geofluids ◽  
2017 ◽  
Vol 2017 ◽  
pp. 1-8 ◽  
Author(s):  
Zhiliang He ◽  
Qian Ding ◽  
Yujin Wo ◽  
Juntao Zhang ◽  
Ming Fan ◽  
...  
Keyword(s):  
Weight Loss ◽  
Open System ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Carbonate Dissolution ◽  
Petroleum Reservoir ◽  
High Quality ◽  
Dissolved Ions ◽  
Effects Of Temperature ◽  
Reaction Fluid

As the most frontiers in petroleum geology, the study of dissolution-based rock formation in deep carbonate reservoirs provides insight into pore development mechanism of petroleum reservoir space, while predicting reservoir distribution in deep-ultradeep layers. In this study, we conducted dissolution-precipitation experiments simulating surface to deep burial environments (open and semiopen systems). The effects of temperature, pressure, and dissolved ions on carbonate dissolution-precipitation were investigated under high temperature and pressure (~200°C; ~70 Mpa) with a series of petrographic and geochemical analytical methods. The results showed that the window-shape dissolution curve appeared in 75~150°C in the open system and 120~175°C in the semiopen system. Furthermore, the dissolution weight loss of carbonate rocks in the open system was higher than that of semiopen system, making it more favorable for gaining porosity. The type of fluid and rock largely determines the reservoir quality. In the open system, the dissolution weight loss of calcite was higher than that of dolomite with 0.3% CO2as the reaction fluid. In the semiopen system, the weight loss from dolomitic limestone prevailed with 0.3% CO2as the reaction fluid. Our study could provide theoretical basis for the prediction of high quality carbonate reservoirs in deep and ultradeep layers.

The transformation effect of source rock-derived acidic fluid on carbonate reservoir from simulation experiments

2020 ◽  
Author(s):  
Qian Ding ◽  
Zhiliang He ◽  
Dongya Zhu
Keyword(s):  
Physical Properties ◽  
Source Rock ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Hydrocarbon Generation ◽  
High Quality ◽  
Simulation Experiments ◽  
Deep Layers

<p>Deep and ultra-deep carbonate reservoir is an important area of petroleum exploration. However, the prerequisite for predicting high quality deep ultra-deep carbonate reservoirs lays on the mechanism of carbonate dissolution/precipitation. It is optimal to perform hydrocarbon generation-dissolution simulation experiments to clarify if burial dissolution could improve the physical properties of carbonate reservoirs, while quantitatively and qualitatively describe the co-evolution process of source rock and carbonate reservoirs in deep layers. In this study, a series of experiments were conducted with the limestone from the Ordovician Yingshan Formation in the Tarim Basin, and the low maturity source rock from Yunnan Luquan, with a self-designed hydrocarbon generation-dissolution simulation equipment. The controlling factors accounted for the alteration of carbonate reservoirs and dissolution modification process by hydrocarbon cracking fluid under deep burial environments were investigated by petrographic and geochemical analytical methods. In the meantime, the transformation mechanism of surrounding rocks in carbonate reservoirs during hydrocarbon generation process of source rock was explored. The results showed that: in the burial stage, organic acid, CO<sub>2</sub> and other acidic fluids associated with thermal evolution of deep source rocks could dissolve carbonate reservoirs, expand pore space, and improve porosity. Dissolution would decrease with the increasing burial depth. Whether the fluid could improve reservoir physical properties largely depends on calcium carbonate saturation, fluid velocity, water/rock ratio, original pore structure etc. This study could further contribute to the prediction of high-quality carbonate reservoirs in deep and ultra-deep layers.</p>

scholarly journals Injection-production optimization of carbonate reservoir based on an inter-well connectivity model

2021 ◽  
pp. 014459872199465
Author(s):  
Yuhui Zhou ◽  
Sheng Lei ◽  
Xuebiao Du ◽  
Shichang Ju ◽  
Wei Li
Keyword(s):  
History Matching ◽  
Water Injection ◽  
Field Application ◽  
Carbonate Reservoir ◽  
Production Optimization ◽  
Oil Field ◽  
Carbonate Reservoirs ◽  
Utilization Rate ◽  
Production Volume ◽  
Connectivity Model

Carbonate reservoirs are highly heterogeneous. During waterflooding stage, the channeling phenomenon of displacing fluid in high-permeability layers easily leads to early water breakthrough and high water-cut with low recovery rate. To quantitatively characterize the inter-well connectivity parameters (including conductivity and connected volume), we developed an inter-well connectivity model based on the principle of inter-well connectivity and the geological data and development performance of carbonate reservoirs. Thus, the planar water injection allocation factors and water injection utilization rate of different layers can be obtained. In addition, when the proposed model is integrated with automatic history matching method and production optimization algorithm, the real-time oil and water production can be optimized and predicted. Field application demonstrates that adjusting injection parameters based on the model outputs results in a 1.5% increase in annual oil production, which offers significant guidance for the efficient development of similar oil reservoirs. In this study, the connectivity method was applied to multi-layer real reservoirs for the first time, and the injection and production volume of injection-production wells were repeatedly updated based on multiple iterations of water injection efficiency. The correctness of the method was verified by conceptual calculations and then applied to real reservoirs. So that the oil field can increase production in a short time, and has good application value.

Research and application of seismic porosity inversion method for carbonate reservoir based on Gassmann’s equation

2021 ◽  
Vol 13 (1) ◽  
pp. 122-129
Author(s):  
Kaiyuan Liu ◽  
Li Qin ◽  
Xi Zhang ◽  
Liting Liu ◽  
Furong Wu ◽  
...  
Keyword(s):  
High Accuracy ◽  
Field Application ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Pore Geometry ◽  
Inversion Method ◽  
Well Testing ◽  
Seismic Attribute ◽  
Gassmann’S Equation ◽  
Inclusion Theory

Abstract Carbonate rocks frequently exhibit less predictable seismic attribute–porosity relationships because of complex and heterogeneous pore geometry. Pore geometry plays an important role in carbonate reservoir interpretation, as it influences acoustic and elastic characters. So in porosity prediction of carbonate reservoirs, pore geometry should be considered as a factor. Thus, based on Gassmann’s equation and Eshelby–Walsh ellipsoidal inclusion theory, we introduced a parameter C to stand by pore geometry and then deduced a porosity calculating expression from compressional expression of Gassmann’s equation. In this article, we present a porosity working flow as well as calculate methods of every parameter needed in the porosity inverting equation. From well testing and field application, it proves that the high-accuracy method is suitable for carbonate reservoirs.

scholarly journals Formation environments and mechanisms of multistage paleokarst of Ordovician carbonates in Southern North China Basin

2021 ◽  
Vol 11 (1) ◽  
Author(s):  
Haitao Zhang ◽  
Guangquan Xu ◽  
Mancai Liu ◽  
Minhua Wang
Keyword(s):  
Carbonate Rocks ◽  
North China ◽  
Oil And Gas ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Geochemical Data ◽  
Near Surface ◽  
Oil And Gas Exploration ◽  
Pore Types ◽  
North China Basin

AbstractWith the reduction of oil and gas reserves and the increase of mining difficulty in Northern China, the carbonate rocks in Southern North China Basin are becoming a significant exploration target for carbonate reservoirs. However, the development characteristics, formation stages, formation environments and mechanisms of the carbonate reservoirs in Southern North China Basin are still unclear, which caused the failures of many oil and gas exploration wells. This study focused on addressing this unsolved issue from the Ordovician carbonate paleokarst in the Huai-Fu Basin, which is located in the southeast of Southern North China Basin and one of the key areas for oil and gas exploration. Based on petrology, mineralogy and geochemical data, pore types, distribution characteristics, and formation stages of the Ordovician paleokarst were analyzed. Then, in attempt to define the origins of porosity development, the formation environments and mechanisms were illustrated. The results of this study showed that pore types of the Ordovician carbonates in the Huai-Fu Basin are mainly composed of intragranular pores, intercrystalline (intergranular) pores, dissolution pores (vugs), fractures, channels, and caves, which are usually in fault and fold zones and paleoweathering crust. Furthermore, five stages and five formation environments of the Ordovician paleokarst were identified. Syngenetic karst, eogenetic karst, and paleoweathering crust karst were all developed in a relatively open near-surface environment, and their formations are mainly related to meteoric water dissolution. Mesogenetic karst was developed in a closed buried environment, and its formation is mainly related to the diagenesis of organic matters and thermochemical sulfate reduction in the Permian-Carboniferous strata. Hydrothermal (water) karst was developed in a deep-buried and high-temperature environment, where hydrothermal fluids (waters) migrated upward through structures such as faults and fractures to dissolve carbonate rocks and simultaneously deposited hydrothermal minerals and calcites. Lastly, a paleokarst evolution model, combined with the related porosity evolution processes, nicely revealed the Ordovician carbonate reservoir development. This study provides insights and guidance for further oil and gas exploration in the Southern North China Basin, and also advances our understanding of the genesis of carbonate paleokarst around the world.

Saturated carbon dioxide nanofluids enhanced oil recovery in carbonate reservoir cores using nuclear magnetic resonance

2021 ◽  
Author(s):  
Yongsheng Tan ◽  
Qi Li ◽  
Liang Xu ◽  
Xiaoyan Zhang ◽  
Tao Yu
Keyword(s):  
Carbon Dioxide ◽  
Nuclear Magnetic Resonance ◽  
Magnetic Resonance ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Residual Oil ◽  
Core Flooding ◽  
Nuclear Magnetic

<p>The wettability, fingering effect and strong heterogeneity of carbonate reservoirs lead to low oil recovery. However, carbon dioxide (CO<sub>2</sub>) displacement is an effective method to improve oil recovery for carbonate reservoirs. Saturated CO<sub>2</sub> nanofluids combines the advantages of CO<sub>2</sub> and nanofluids, which can change the reservoir wettability and improve the sweep area to achieve the purpose of enhanced oil recovery (EOR), so it is a promising technique in petroleum industry. In this study, comparative experiments of CO<sub>2</sub> flooding and saturated CO<sub>2</sub> nanofluids flooding were carried out in carbonate reservoir cores. The nuclear magnetic resonance (NMR) instrument was used to clarify oil distribution during core flooding processes. For the CO<sub>2</sub> displacement experiment, the results show that viscous fingering and channeling are obvious during CO<sub>2</sub> flooding, the oil is mainly produced from the big pores, and the residual oil is trapped in the small pores. For the saturated CO<sub>2</sub> nanofluids displacement experiment, the results show that saturated CO<sub>2</sub> nanofluids inhibit CO<sub>2</sub> channeling and fingering, the oil is produced from the big pores and small pores, the residual oil is still trapped in the small pores, but the NMR signal intensity of the residual oil is significantly reduced. The final oil recovery of saturated CO<sub>2</sub> nanofluids displacement is higher than that of CO<sub>2</sub> displacement. This study provides a significant reference for EOR in carbonate reservoirs. Meanwhile, it promotes the application of nanofluids in energy exploitation and CO<sub>2</sub> utilization.</p>

The effect of feeding different protein sources on intake, milk yield, milk composition and liveweight in high yielding Holstein cows

1998 ◽  
Vol 1998 ◽  
pp. 202-202
Author(s):  
R J Mansbridge ◽  
J S Blake
Keyword(s):  
Weight Loss ◽  
Public Awareness ◽  
Block Design ◽  
Milk Composition ◽  
Holstein Cows ◽  
High Quality ◽  
Protein Sources ◽  
Sufficient Energy ◽  
Soyabean Meal ◽  
The Uk

High yielding cows require high quality diets to sustain milk yields and to minimise weight loss, metabolic disorders and fertility problems. Traditionally, these diets have contained fishmeal and soyabean meal, both widely regarded as good sources of high quality, digestible undegraded protein (DUP). However, there is increasing concern over the sustainability of world fish stocks and the BSE scare has increased public awareness to the extent that feeding animal protein to herbivores may become unacceptable in me future. This in turn has driven up the price of high quality imported vegetable proteins, such as soyabean meal. The aim of this study was to investigate whether fishmeal and soyabean meal could be replaced in the diet of high yielding cows, with protein sources grown in the UKIn a 12 week randomised block design experiment, 60 muciparous Holstein cows, on average 28 days calved at the start of the study, were fed total mixed rations based on grass silage and one of five protein mixtures. These were either 0.5 kg DM fishmeal + 0.7 kg DM soya + 2.5 kg DM rapeseed (PC), 1.3 kg DM soyabean + 2.3 kg DM rapeseed (PI), 3.8 kg DM lupins + 2.3 kg DM heat treated rapeseed (P2), 3.6 kg DM linseed + 1.4 kg DM rapeseed (P3) or 5.8 kg DM rapeseed (P4). Each diet was formulated to supply sufficient energy and metabolisable protein for maintenance + 43 litres and 0.75kg/d weight loss and to contain similiar levels of DUP (AFRC, 1993).

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.

The New Flow Control Devices Autonomously Controlling the Performance of Matrix Acid Stimulation Operations in Carbonate Reservoirs

2021 ◽  
Author(s):  
Mojtaba Moradi ◽  
Michael R Konopczynski
Keyword(s):  
Flow Control ◽  
Dynamic Change ◽  
Injection Rate ◽  
Control Flow ◽  
Carbonate Reservoir ◽  
Operating Conditions ◽  
Carbonate Reservoirs ◽  
High Permeability ◽  
The Impact ◽  
Stimulation Of

Abstract Matrix acidizing is a common but complex stimulation treatment that could significantly improve production/injection rate, particularly in carbonate reservoirs. However, the desired improvement in all zones of the well by such operation may not be achieved due to existing and/or developing reservoir heterogeneity. This paper describes how a new flow control device (FCD) previously used to control water injection in long horizontal wells can also be used to improve the conformance of acid stimulation in carbonate reservoirs. Acid stimulation of a carbonate reservoir is a positive feedback process. Acid preferentially takes the least resistant path, an area with higher permeability or low skin. Once acid reacts with the formation, the injectivity in that zone increases, resulting in further preferential injection in the stimulated zone. Over-treating a high permeability zone results in poor distribution of acid to low permeability zones. Mechanical, chemical or foam diversions have been used to improve stimulation conformance along the wellbore, however, they may fail in carbonate reservoirs with natural fractures where fracture injectivity dominates the stimulation process. A new FCD has been developed to autonomously control flow and provide mechanical diversion during matrix stimulation. Once a predefined upper limit flowrate is reached at a zone, the valve autonomously closes. This eliminates the impact of thief zone on acid injection conformance and maintains a prescribed acid distribution. Like other FCDs, this device is installed in several compartments in the wells. The device has two operating conditions, one, as a passive outflow control valve, and two, as a barrier when the flow rate through the valve exceeds a designed limit, analogous to an electrical circuit breaker. Once a zone has been sufficiently stimulated by the acid and the injection rate in that zone exceeds the device trip point, the device in that zone closes and restricts further stimulation. Acid can then flow to and stimulate other zones This process can be repeated later in well life to re-stimulate zones. This performance enables the operators to minimise the impacts of high permeability zones on the acid conformance and to autonomously react to a dynamic change in reservoirs properties, specifically the growth of wormholes. The device can be installed as part of lower completions in both injection and production wells. It can be retrofitted in existing completions or be used in a retrievable completion. This technology allows repeat stimulation of carbonate reservoirs, providing mechanical diversion without the need for coiled tubing or other complex intervention. This paper will briefly present an overview of the device performance, flow loop testing and some results from numerical modelling. The paper also discusses the completion design workflow in carbonates reservoirs.

scholarly journals Bulk and Surface Aqueous Speciation of Calcite: Implications for Low-Salinity Waterflooding of Carbonate Reservoirs

SPE Journal ◽  
2017 ◽  
Vol 23 (01) ◽  
pp. 84-101 ◽  
Author(s):  
Maxim P. Yutkin ◽  
Himanshu Mishra ◽  
Tadeusz W. Patzek ◽  
John Lee ◽  
Clayton J. Radke
Keyword(s):  
Ionic Strength ◽  
Ion Exchange ◽  
Crude Oil ◽  
Surface Charge ◽  
Double Layer ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Diffuse Double Layer ◽  
Low Salinity ◽  
Low Salinity Waterflooding

Summary Low-salinity waterflooding (LSW) is ineffective when reservoir rock is strongly water-wet or when crude oil is not asphaltenic. Success of LSW relies heavily on the ability of injected brine to alter surface chemistry of reservoir crude-oil brine/rock (COBR) interfaces. Implementation of LSW in carbonate reservoirs is especially challenging because of high reservoir-brine salinity and, more importantly, because of high reactivity of the rock minerals. Both features complicate understanding of the COBR surface chemistries pertinent to successful LSW. Here, we tackle the complex physicochemical processes in chemically active carbonates flooded with diluted brine that is saturated with atmospheric carbon dioxide (CO2) and possibly supplemented with additional ionic species, such as sulfates or phosphates. When waterflooding carbonate reservoirs, rock equilibrates with the injected brine over short distances. Injected-brine ion speciation is shifted substantially in the presence of reactive carbonate rock. Our new calculations demonstrate that rock-equilibrated aqueous pH is slightly alkaline quite independent of injected-brine pH. We establish, for the first time, that CO2 content of a carbonate reservoir, originating from CO2-rich crude oil and gas, plays a dominant role in setting aqueous pH and rock-surface speciation. A simple ion-complexing model predicts the calcite-surface charge as a function of composition of reservoir brine. The surface charge of calcite may be positive or negative, depending on speciation of reservoir brine in contact with the calcite. There is no single point of zero charge; all dissolved aqueous species are charge determining. Rock-equilibrated aqueous composition controls the calcite-surface ion-exchange behavior, not the injected-brine composition. At high ionic strength, the electrical double layer collapses and is no longer diffuse. All surface charges are located directly in the inner and outer Helmholtz planes. Our evaluation of calcite bulk and surface equilibria draws several important inferences about the proposed LSW oil-recovery mechanisms. Diffuse double-layer expansion (DLE) is impossible for brine ionic strength greater than 0.1 molar. Because of rapid rock/brine equilibration, the dissolution mechanism for releasing adhered oil is eliminated. Also, fines mobilization and concomitant oil release cannot occur because there are few loose fines and clays in a majority of carbonates. LSW cannot be a low-interfacial-tension alkaline flood because carbonate dissolution exhausts all injected base near the wellbore and lowers pH to that set by the rock and by formation CO2. In spite of diffuse double-layer collapse in carbonate reservoirs, surface ion-exchange oil release remains feasible, but unproved.

Polymer Injection to Unlock Bypassed Oil in a Giant Carbonate Reservoir: Bridging the Gap Between Laboratory and Large Scale Polymer Project

2021 ◽  
Author(s):  
Clement Fabbri ◽  
Haitham Ali Al Saadi ◽  
Ke Wang ◽  
Flavien Maire ◽  
Carolina Romero ◽  
...  
Keyword(s):  
High Salinity ◽  
Water Injection ◽  
Cross Flow ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Laboratory Work ◽  
High Permeability ◽  
Polymer Injection ◽  
Single Well ◽  
Pilot Design

Abstract Polymer flooding has long been proposed to improve sweep efficiency in heterogeneous reservoirs where polymer enhances cross flow between layers and forces water into the low permeability layers, leading to more homogeneous saturation profile. Although this approach could unlock large volumes of by-passed oil in layered carbonate reservoirs, compatibility of polymer solutions with high salinity - high temperature carbonate reservoirs has been hindering polymer injection projects in such harsh conditions. The aim of this paper is to present the laboratory work, polymer injection field test results and pilot design aimed to unlock target tertiary oil recovery in a highly heterogeneous mixed to oil-wet giant carbonate reservoir. This paper focuses on a highly layered limestone reservoir with various levels of cyclicity in properties. This reservoir may be divided in two main bodies, i.e., an Upper zone and a Lower zone with permeability contrast of up to two orders of magnitude. The main part of the reservoir is currently under peripheral and mid-flank water injection. Field observations show that injected water tends to channel quickly through the Upper zone along the high permeability layers and bypass the oil in the Lower zone. Past studies have indicated that this water override phenomenon is caused by a combination of high permeability contrast and capillary forces which counteract gravity forces. In this setting, adequate polymer injection strategy to enhance cross-flow between these zones is investigated, building on laboratory and polymer injection test field results. A key prerequisite for defining such EOR development scenario is to have representative static and dynamic models that captures the geological heterogeneity of this kind of reservoirs. This is achieved by an improved and integrated reservoir characterization, modelling and water injection history matching procedure. The history matched model was used to investigate different polymer injection schemes and resulted in an optimum pilot design. The injection scheme is defined based on dynamic simulations to maximize value, building on results from single-well polymer injection test, laboratory work and on previous published work, which have demonstrated the potential of polymer flooding for this reservoir. Our study evidences the positive impact of polymer propagation at field scale, improving the water-front stability, which is a function of pressure gradient near producer wells. Sensitivities to the position and number of polymer injectors have been performed to identify the best injection configuration, depending on the existing water injection scheme and the operating constraints. The pilot design proposed builds on laboratory work and field monitoring data gathered during single-well polymer injection field test. Together, these elements represent building blocks to enable tertiary polymer recovery in giant heterogeneous carbonate reservoirs with high temperature - high salinity conditions.

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