Na, Li (Faculty of Geographical Science, Beijing Normal University, 100875, Beijing, China) | Jinliang, Zhang (Faculty of Geographical Science, Beijing Normal University, 100875, Beijing, China) | Jinshui, Liu (Shanghai Branch, CNOOC Ltd., 200030, Shanghai, China) | Wenlong, Shen (Shanghai Branch, CNOOC Ltd., 200030, Shanghai, China) | Hao, Chen (Shanghai Branch, CNOOC Ltd., 200030, Shanghai, China) | Guangchen, Xu (Faculty of Geographical Science, Beijing Normal University, 100875, Beijing, China)
Summary The prediction of source rocks is very important to the basin at the initial stage of exploration, among which the description of the source rocks' spatial distribution and the evaluation of the source rocks' thickness are the most significant. For most of the oil and gas fields on the land, the prediction and evaluation of source rocks rely on geochemistry analysis. But well data is inadequate on the offshore exploration area. Therefore, seismic data and geophysical methods can be applied to improve the prediction accuracy of source rocks. Data and Method In this research, the main data relate to core, logging, seismic from Lishui Sag, China (Figure 1).
Simon, Matthieu (Schlumberger) | Tkabladze, Avto (Schlumberger) | Beekman, Sicco (Schlumberger) | Atobatele, Timothy (Schlumberger) | De Looz, Marc-André (Schlumberger) | Grover, Rahul (Schlumberger) | Hamichi, Farid (Schlumberger) | Jundt, Jacques (Schlumberger) | McFarland, Kevin (Schlumberger) | Mlcak, Justin (Schlumberger) | Reijonen, Jani (Schlumberger) | Revol, Arnaud (Schlumberger) | Stewart, Ryan (Schlumberger) | Yeboah, Jonathan (Schlumberger) | Zhang, Yi (Schlumberger)
Formation bulk density is classically measured by irradiating the formation with gamma rays emitted by a 137Cs source, and counting the Compton scattered photons returning to the gamma-ray detectors in the well-logging instrument. Finding a suitable replacement for the 137Cs source has been difficult. The X-ray source described in this paper appears to be a robust replacement for this type of source.
The continued success of 137Cs sources in density logging shows that attempts at their replacement have been unsuccessful due to the insufficient measurement quality or lack of practicality of alternative logging instruments.
An X-ray density-pad sonde was engineered to measure bulk density without a radioisotopic source. The pad contains a rugged, compact X-ray generator with an endpoint energy larger than 300 keV. The core of the tool is the generator, which emits a controlled, focused, stable X-ray flux into the formation. The scattered X-rays are detected by strategically placed scintillation detectors. The pad-tool architecture significantly reduces the effects of standoff and borehole rugosity compared to a mandrel design.
Modeling and experimental data show that the physics of the formation density measurement using a sonde with an X-ray generator and scintillation detectors can be described in the same way as the traditional density measurement, which is based on a monoenergetic gammaray source. Although the 137Cs gamma-ray source density measurement and the X-ray density measurement differ in the relative magnitude of the responses to formation density and lithology (photoelectric factor, PEF), the fundamental physics is the same. An endpoint energy above 300 keV ensures that the transport and attenuation of X-rays in the formation are dominated by Compton scattering, like the attenuation of gamma rays from a 137Cs source. The contribution of the photoelectric absorption to the attenuation of the X-rays is increased, but remains much smaller than the effect of Compton scattering, making the corrections for lithology and borehole fluid straightforward.
A characterization database was acquired to probe the physics of the measurement and to derive robust density and PEF algorithms. Plots of near- and far-detector count rates for different mudcake thicknesses and mud types show spine-and-ribs behavior like 137Cs-based density tools. Field logs acquired with the new tool show improved precision and vertical resolution compared to the 137Cs source tools suggesting that this new tool may be a viable replacement for the older tools.
Yang, Zhao (PetroChina) | Fenjin, Sun (PetroChina) | Bo, Wang (PetroChina) | Xianyue, Xiong (PetroChina) | Wuzhong, Li (PetroChina) | Lianzhu, Cong (PetroChina) | Jiaosheng, Yang (PetroChina) | Meizhu, Wang (PetroChina)
Compared with the conventional oil and gas reservoirs, hydrogeological gas controlling process linking CBM accumulation, enrichment and high yield is one of the important scientific problems for the development of a CBM field. Previous research results are mainly focused on the impact of hydrodynamics on CBM dissipation, preservation and enrichment, whereas relatively less work has been done on the quantitative evaluation of the hydrochemical field of CBM and establishing evaluation indicators of CBM enrichment. Therefore, taking BQ Well area of Hancheng block in east Ordos Basin as an example, this paper tried to initiate a systematic analysis of the controlling function of hydrogeological conditions on the enrichment and high yield of CBM in the study area. Hydrological evaluation indicators for hydrocarbon enrichment zones are established and two favorable hydrocarbon enrichment zones are optimized. It is of great significance for the established analytical method of hydrogeological rule on the studies of CBM enrichment characteristics and development in Hancheng CBM block, and subsequent exploration & development in the neighboring blocks.
Firstly, the relevant principle of hydrodynamics is applied to identify substantive parameters, such as measured in-situ reservoir pressure and CBM reservoir water level in the production wells to calculate the reduced water level and analyze groundwater level distribution characteristics; secondly, combined with the analysis of groundwater water types, the sources of the produced water from coal beds are identified, and the sealing property of the reservoir is demonstrated; on this basis, the study area is divided into the weak runoff zone and the stagnation zone. It is considered that the runoff intensity is relatively weak and the sealing capability is good in the study area, with no external water intrusion; finally, it is considered that, through integrated studies on the hydrochemical field, the desulfuration coefficient and sodium chloride coefficient can reflect the diversity of CBM reservoir conditions in a more elaborated way. Hydrological indicators based on hydrochemical characteristics are established, and two favorable enrichment zones are predicted.
This work proved that hydrogeological features of CBM reservoirs are able to characterize their accumulation conditions elaborately. In particular, the establishment of hydrological indicators can classify favorable enrichment zones and hereafter guide following CBM exploration & development. This methodology has been satisfactorily applied in BQ well area of Hancheng block where the data of gas bearing capacity is limited. High single well production rates have been obtained in the two predicted favorable enrichment zones. The hydrological indicators established in this paper are expected to be popularized and applied in other well areas of Hancheng block, which may accelerate the overall exploration & development progress in this block.
Hydrocarbon-bearing ultra-tight formations generally exhibit heterogeneous, anisotropic, and pressure-dependent petrophysical properties. Consequently, various laboratory measurements on separate core plugs and crushed rock samples from tight formations tend to generate inconsistent petrophysical estimates. These inconsistencies are further escalated by the existence of varied pressure- and pore-size-dependent fluid flow mechanisms in the nanopores of ultra-tight formations. We circumvent such discrepancies in petrophysical estimates by simultaneously estimating six petrophysical parameters from laboratory-based pressure-step-decay measurement on a single ultra-tight rock sample. The proposed method involves nitrogen gas injection into an ultra-tight rock sample at multiple stepwise pressure increments, high-resolution pressure-decay measurement at the outlet, followed by a deterministic inversion of the measured downstream pressure data based on numerical finite-difference modeling of nitrogen gas flow in the ultra-tight rock sample.
This work is performed with an aim to improve the petrophysical estimates previously obtained from pressure-step-decay measurements using only a Klinkenberg-type gas slippage model. We implement a transitional transport model that can handle both slip and diffusion. The proposed method was applied to nine 2-cm-long, 2.5-cm-diameter core plugs extracted from a 1-ft3 ultra-tight pyrophyllite block. We estimated the intrinsic permeability, effective porosity, pore-volume compressibility, pore throat diameter, and two slippage-Knudsen diffusion weight factors parameters. Accuracy of the estimates depends on the physical models incorporated in the forward model and on the error minimization algorithm implemented in the inversion scheme. The estimation results are independent of initial guess of intrinsic permeability, effective porosity pore-volume compressibility, and pore throat diameter in the range of 3 nd to 300 nd, 0.01 to 0.15, 10-2 to 10-6 psi-1, and 60 nm to 500 nm, respectively. The average estimated values of intrinsic permeability, effective porosity, pore-volume compressibility, and pore throat diameter of the nine ultra-tight samples are 86 nd, 0.036, 2.6E-03 psi-1, and 195 nm, respectively. Notably, the two inverted slippage-Knudsen diffusion weight factors indicate that the gas transport mechanism in the nine ultra-tight pyrophyllite samples is completely dominated by slip flow without any Knudsen diffusion or transitional flow even though the Knudsen numbers across the samples during the entire duration of the pressure-step-decay measurements are in the range of 0.01 to 1.
Reservoir depletion results in changes in effective stresses, which may lead to significant changes in reservoir permeability. These changes are associated with matrix compaction, fracture closure and potential slip. A depletion-induced increase in effective stresses often leads to a decrease in permeability. However, the opposite is observed to happen in some fractured gas reservoirs with an organic rock matrix that exhibits strong sorption-mechanical coupling. During depletion, an adsorbed portion of the gas desorbs from micropores resulting in shrinkage of the organic components in the rock matrix, effective stress relaxation and a potential increase in fracture permeability. The objective of this study is to develop a reservoir simulator with a full mechanical coupling accounting for sorption-induced change of stresses. This paper aims to estimate the influence of the parameters affecting reservoir permeability and to predict its evolution during reservoir depletion. We compare two natural gas fields with strong (San Juan coal basin) and weak (Barnett shale formation) sorption-mechanical coupling. The results of the study highlight the interplay between mechanical moduli, swelling isotherm parameters, and fracture compressibility in determining the impact of desorption on fracture permeability evolution during depletion.
Natural gas consumption currently constitutes a fifth of the total energy sources . About a half of nonassociated gas accrues to non-conventional gas reservoirs, mainly organic shales and coal seams . Non-conventional tight reservoirs have an extremely low permeability, a fair portion of which pertains to fractures as main fluid conduits. The openings of these fractures are dictated by lithology and the reservoir stresses, which may alter during reservoir development [2-5]. Two competitive geomechanical processes are known to affect stresses during depletion in organic-rich rocks: pressure drawdown and desorption-induced shrinkage. The latter is of significant importance in coals because sorbed gas constitutes more than 50% of total gas in place and desorption induces a substantial amount of rock shrinkage [6-8]. Sorbed gas in hydrocarbon-bearing shales constitutes 5-15% of the total gas in place. Sorption capacity is usually proportional to total organic carbon (TOC) in shales . Decreases in pore pressure associated with reservoir depletion cause increases in effective stresses, which often leads to fracture closure and a decrease in permeability. In contrast, desorption and matrix shrinkage result in a drop in effective stresses and an increase in permeability [8, 10, 11].
The Niagara Tunnel Project (NTP) is a 10.1 km long water-diversion tunnel in Niagara Falls, Ontario, which was excavated by a 14.4 m diameter tunnel boring machine. The excavated rock types included limestone, sandstone, siltstone, shale and mudstone. Based on observations and measurements the overbreak was divided into four zones. Approximately half the tunnel length was excavated through the Queenston Formation, which locally is a shale to mudstone. Three of the four overbreak zones were within the Queenston. Zone 1 includes the formations above the Queenston Formation, Zones 2 and 4 are border regimes with little or no influence from St. Davids Buried Gorge and Zone 3 is the area influenced by the gorge. Zones 2 through 4 can be generally summarized as having overbreak as the result of stress induced spalling. Zone 2 marks the transition from slabbing at the Whirlpool contact in the stress shadow to spalling towards Zone 3. The behaviour of Zone 3 is interrupted from the typical high stress behaviour due to the presence of St. Davids Buried Gorge. As the tunnel passed from the gorge the high regional stresses induce spalling, which creates the typical notch shaped overbreak geometry of Zone 4.
Three modelling approaches were used to back analyze the brittle failure process at the NTP: damage initiation and spalling limit, laminated anisotropy modelling, and ubiquitous joint approaches. Analyses were conducted for three tunnel chainages: 3+000, 3+250, and 3+500 m because the overbreak depth increased from 2 to 4 m. All approaches produced similar overbreak geometries to those measured. The laminated anisotropy modelling approach was able to produce overbreak depths and chord closures closest to those measured, using a joint normal to shear stiffness ratio between 1 and 2. The back analysis results were able to produce sets of stress and strength inputs for different sections of the tunnel at the transition from overbreak Zone 3 to 4. The back analysis procedure demonstrates the importance of including the anisotropic stiffness in the numerical modelling approach to correctly capture the overbreak geometry and deformations around underground excavations.
The significance of unconventional gas reservoirs has been increasing for recent years owing to economic viability of their development, therefore assessment of the challenges and common pitfalls regarding those resources have been gaining importance at the same time. In this regard, the optimization of production performance of these reservoirs with the different well trajectories and completion techniques and identifying the best case scenario become more significant. That is absolutely challenging process due to the several reasons such as ultra-low permeability, desorption effect, and complex geological characteristics. However, it is possible to analyze the various parameters and observe their impact on each system with the help of advances in algorithms, computer power, and integrated software. The objective of this work is to investigate and understand the effect of some reservoir and completion parameters on the future production performance of shale gas and coal bed methane (CBM) reservoirs. A practical model is constructed with the field and synthetic data for the analysis of gas production rate and cumulative gas production versus time in multi-layered shale gas and CBM reservoirs respectively. Changes in the thickness of various stratified layers, permeability, wellbore position, number of hydraulic fracture stage, and also production profile of each system are studied using different well trajectories. The results are obtained by running a series of reservoir simulation conducted by a commercial numerical simulator with dual porosity model for CBM and shale gas reservoirs.
Al-dahlan, Mohammed N (Saudi Aramco PE&D) | Al-Obied, Marwa Ahmad (Saudi Aramco PE&D) | MARSHAD, KHALID Mohammad (Saudi Aramco PE&D) | Sahman, Faisal M (Saudi Aramco) | Al-Yami, Ibrahim Saleh (Saudi Aramco PE&D) | AlHajri, Abdullah (Saudi Aramco PE&D)
Description of the material
This paper presents the results of the study conducted on HCl-Replacement-Acid (HRA), a synthetic HCl replacement chemical, with health hazard rating of one and dissolving power similar to HCl. An extensive experimental scheme including: thermal stability, dissolving power, acidity, compatibility, corrosion rate & inhibition and coreflooding on carbonate formation core plugs was conducted.
Acid treatments of carbonate formations are usually carried out using mineral acid (HCl), organic acids (formic and acetic), mixed acids (HCl-formic, HCl-acetic), and retarded acids. The major challenges when using these acids are their high corrosion rate, fast reaction rate and health hazard. The improvement in corrosion inhibitors makes the use of strong acid as high as 28 wt% HCl possible. The acid reaction rate can be controlled by decreasing diffusion rate of hydronium ions (H+) to the rock surface where reactions take place by increasing acid viscosity using gelling agent or emulsifying acid droplet in a hydrocarbons liquid, acid-in-diesel emulsion. While the issues of stimulation acids reaction and corrosion rates are relatively controlled, these acids health hazard rating of 3 by the National Fire Protection Association (NFPA) is major concern. A health hazard rating of 3 is defined as an extreme danger where short exposure could cause serious injury
Results, Observations, and Conclusions
Based on this study results, the HRA was found to be thermally stable with similar dissolving power to 15 wt% HCl and lower corrosion rate. In addition, the HRA developed a breakthrough on core plugs with average pore volume (PV) of 2.7 and approximately 3 folds increase in permeability.
Significance of subject matter
An acid replacement chemical that has no or minimum health hazard rating while still has the ability to dissolve carbonate rock would be a major forward step in stimulation technology.
Graptolite shales are a type of fossil shales that contain a large number of graptolite imprints and remains. These deposits are characterized by high TOC contents (Corg = 2–18%). Based on the data of many studies, graptolite shales are one of the main hydrocarbon sources that formed oil and gas fields in Paleozoic deposits around the world, e.g., the Silurian graptolite shales make up to 9–15% of all hydrocarbons that form the oil and gas fields in the largest petroleum basins.
The main accumulation areas of graptolite shales during the Ordovician were the margins of Baltica, Laurentian, and Gondwana (Yapetus Ocean shelf). One of the belts (northern) extended from the southern periphery of the Baltic Shield to the Appalachian Basin; another (southern) belt stretched from the sedimentary basins of the African–Arabian margin of Gondwana to the shelf and continental slope of southern Laurentia, the present-day Western Interior Coal Region, Permian basin, and Ouachita belt. In the Silurian, the southern (northern Gondwanan) belt began
to play the leading role, while another northern belt incorporated the southern regions of Baltica and the microcontinents approaching to it (Armorica, Perunica, and Iberica). In the sedimentary basins of Laurentia, Silurian graptolite shales were not widespread; they are reported only for east Greenland and in the Michigan basin. The contribution of Paleozoic graptolite shales into
the generation of hydrocarbons that formed multiple oil and gas fields worldwide is quite high. Based on the data of G. Ulmishek and H. Klemme (1991), oil-and-gas source rocks of Ordovician and Silurian ages, which are mostly graptolite shales, produced up to 9% of all the hydrocarbon reserves discovered by the late 20th century. For particular regions, this contribution was even more. It is believed that Silurian graptolite shales produced 80 to 90% of the hydrocarbons stored in giant oil field of North Africa. The Silurian graptolite shales are also thought to have played the main role in the formation of the South Pars/North Field gas condensate field in the Persian Gulf, which is the largest field for natural gas in the world.
During work with more than 41 publications schemes of distribution of graptolitic shales in Ordovician and Silurian was composed. Such knowledge about source rock is one of the many steps to Petroliferous basins insight.
Keywords: graptolite shales, Silurian, Ordovician, Yapetus, Rheic Ocean
Graptolites, or the Graptolithina class (Greek graptos: painted, drawn; lithes: stone) are referred to the Hemichordata type. In contrast to true Chordata, this is expressed not by a long tenia, but a small dorsal apophysis of the intestine in the pharynx zone. Graptolite remains are preserved in the form of small tubes that are united into colonies of up to 10 cm in size. These pipes (thecae) are of chitine-like appearance and of scleroprotein (condensed protein polymers), not chitine (carbohydrate polymers) composition, as was previously believed. The cells are up to 1 mm in cross size and up to 4 mm long; they are of cylindrical, conic, beak_like, or hook-like shapes. The first theca of a colony, which is called a sicula (Greek sicula; small dagger) is narrow–conic in shape. Graptolites are marine organisms that lived in the seawater of normal salinity according to the way of life of benthic, plankltonic, and pseudoplanktonic animals. “Siculae of benthic and pseudoplanktonic colonies have a thread-like sprout or basal plate, with which a colony is attached to the bottom or any floating objects. Some planktonic graptolite colonies contain air bubbles” (Mikhailova and Bondarenko, 2006).
Carbonate sedimentary rocks that have been fractured, or dolomitized and laterally sealed by tight undolomitized limestone, are frequently seen to produce hydrocarbons. However, the differentiation between limestones and dolomites is a challenge. The purpose of this work is to describe a workflow for discriminating limestones and dolomites, and to map the lateral extent of dolomite reservoir rocks that have a thickness below the seismic resolution.
For this study, we have used the photoelectric index (Pe) well log curve as it is a sensitive indicator of mineralogy. At any well location, Pe exhibits somewhat higher, but flat trend for background limestone. Relative to this flat trend the dolomite units are represented by low values of Pe. However, such well log curves are available only at the location of the wells. We demonstrate an approach of computing Pe volume from the seismic P- and S-impedance volumes. We begin our exercise by crossplotting the P-impedance (IP) against the S-impedance (IS) color coded with Pe curve using the well log data. In IP-IS crossplot space, we highlight the discrimination between the limestone and dolomite clusters by choosing an axis of rotation to highlight the desired discrimination. The result of such a rotation is a single display attribute we call lithology impedance (LI) to identify the formation lithology. Furthermore, its relationship with the Pe curve is established for obtaining Pe volume from the seismic data. The issue of the resolution of the seismic data is addressed by using a thinbed reflectivity inversion.