Particle size, shape and mineralogy are considered as primary characteristics of sand and sandstone. Several techniques have been developed for the particle size and shape analysis of unconsolidated sands. However, few of these techniques can be used for sandstones. Most particle size measurement techniques provide a spherical equivalent of the particle size and neglect the particle shape. Although several techniques have been developed for the particle size and shape analysis of the unconsolidated sands, these techniques could not be used for the size and shape variation analysis of consolidated or semi-consolidated sandstone.
Recently, X-ray micro CT scanning technique has been used for the evaluation of petrophysical properties of sandstones. This paper presents a workflow for the measurement of particle size and shape of sandstones. This research utilized X-ray micro CT scans for 2-dimensional particle shape measurements including Sphericity, Convexity, Aspect Ratio and Feret diameters. The methodology presented in this paper is the first step toward assessing the particle shape and size variation of sandstones for use in such applications as sand control design.
Image-J, an Open-source software, was used to process and filter the X-ray raw images. A new tool was developed to measure the shape factors (i.e. Sphericity, Aspect Ratio and Convexity) and size variations. A series of images from different sandstones were analyzed and compared to their lab measurements. The image calculated porosity and permeability showed some degree of deviation from the lab measured porosity and permeabilities.
This paper presents a new workflow to measure the particle size and shape for the sand control design in sandstone reservoirs. With a larger database it is possible to develop a correlation to calculate rock properties from image size analysis technique and correct them for the shape variation. The next step will be to measure the 3D size and shape from the image analysis and compare to the shape and size analysis from dynamic image analysis.
Wang, Chunpeng (PetroChina Research Institute of Petroleum Exploration & Development) | Cui, Weixiang (PetroChina Research Institute of Petroleum Exploration & Development) | Zhang, Hewen (PetroChina Research Institute of Petroleum Exploration & Development) | Qiu, Xiaohui (PetroChina Research Institute of Petroleum Exploration & Development) | Liu, Yuting (PetroChina Research Institute of Petroleum Exploration & Development)
In view of tight oil reservoirs with no natural productivity (tight sandstone and carbonate reservoirs with matrix permeability under overburden pressure of no more than 0.2mD (pore permeability less than 2mD)), a nanometer high efficient oil washing agent has been developed by combining nano-drop, high efficient oil washing surfactant and wettability reversal means, which can turn the disadvantage of the small pores and throats into advantage and realize fracturing effect enhancement by making use of the spontaneous imbibition.
For the tight oil reservoir, large scale and high pumping rate multi-stage fracturing in horizontal wells and fracture diversion technique are recommended to smash the reservoirto create a fracture network of natural fractures and artificial fractures for oil and gas flow. The aim is to increase reservoir stimulation volume and the artificial fracture area. Meanwhile, nanometer high efficient oil washing agent is added in the fracturing fluid. By changing rock wettability, the oil-wet interface is turned water-wet, and the capillary force is changed from imbibition resistance to imbibition drive, boosting spontaneous imbibition. Therefore, the biobased solvent and surfactant can work in synergy to separate the oil film from pore and throat surface, realizing displacement of oil by water. Experimental data shows the application the nanometer oil displacement agent can enhance the oil displacement efficiency of core by12%. After fracturing, the well should be shut down for some time. The shut-down time should take the reservoir pressure and temperature, pore structure and connectivity and the imbibition capacity of the fracturing fluid etc into account, and can be worked out by spontaneous imbibition experiment and NMR etc to guide field operation.
This technology has been used 10 well times in tight oil reservoirs in western China, including 3 well times of key exploration well stimulation, and 7 well times of old well repeated fracturing, all the treatments have achieved good effect. Among them, one well worth special note, this well had no production before fracturing, but obtained a high production of 42t a day after fracturing. During the shutdown of well, the fracturing fluid in the artificial fracture network can contact fully with micro-pores in the matrix and displace the oil in them through imbibition to the fracture system, then the oil can flow along the fracture network to the well bottom.
The high efficient imbibition fracturing technology for tight oil reservoir is a revolution in fracturing. With fracturing fluid system and well shutdown different from traditional fracturing, this technology can enhance fracturing effect and more importantly oil recovery. This paper has great guidance and reference significance for engineers and researchers engaged in tight oil development.
Hydraulic Fracturing has been used successfully in the oil and gas industry to enhance oil and gas production. Recent years have seen the great development of tight gas, coalbed methane, and shale gas. Different fluids were used as fracturing fluids in shale and sandstone formations, including the use of CO2, N2 and CO2 foam, slick water, crosslinked solutions, and oil-based fracturing fluids. The objective of this study is to develop an experimental setup to measure the breakdown pressure to initiate the fractures in shale and tight sandstone cores.
This study investigated the effect of injection flow rate, temperature, fluid viscosity, and fluid type on the breakdown pressure of different rock cores. 5 wt% KCl brine, slick water with a friction reducer, linear gel systems were used as a fracturing fluid. Kentucky, Scioto, Bandera, and Berea sandstone cores were used. Also, Mancos, Marcellus, and Barnett shale cores were used in this study. Finally, the behavior of the breakdown pressure was examined as a function of the back pressure (0, 100, 300 psi).
The preliminary results show that the breakdown pressure increased as the injection flow rate increased. Where the breakdown pressure increased from 438 to 1,000 psi as the flow rate increased from 5 to 10 cm3/min in case of 5 wt% KCl with Kentucky sandstone cores. The breakdown pressure increased in Marcellus shale to 1,800 psi in case of 5 wt% KCl at 5 cm3/min. As the fluid viscosity increased the breakdown pressure increased, it increased to 1,115 psi in case of 2 gptg friction reducer (5 cp) comparing to 5 wt% KCl (1.1 cp) case at 5 cm3/min. A straight line relationship was found between the breakdown pressure and the logarithmic scale of the fluid viscosity.
This study will give recommendations for the fluid viscosity, type, and the injection flow rate that will improve the efficiency of the hydraulic fracturing operation.
The sustained casing pressure (SCP) in shale gas wells caused by cement sheath failure can have serious impacts on safe and efficient gas production. Although horizontal wells are widely used for production from Shales, the cementing quality and casing centericity is barely ensured. Among other indications, the casing off-center is iedtified very often in the wells with SCP problem in Sichuan field. Hence, the objective of this study is to analyze the effect of the casing off-center on the integrity of the cement sheath. To better understand stress distribution in eccentric cement sheaths, an analytical model is proposed in this paper. By comparing the results of this model with the centeric casing, the impacts of casing off-center on integrity of the cement sheath is analyzed. During the fracturing treatment, the casing off-center has little effect on stress in the cement sheath if the well is well cemented and bonded to the formation rock. But on the contrary, the casing off-center has serious effects on stress distribution if the cementing is done poorly. The debonding of casing-cement-formation interfaces can significantly increase the circumferential stress at the cement sheath. At the narrow side of the cement sheath, the circumferential stress could be 2.5 times higher than the thick side. The offset magnitude of the casing eccentricity has little effect on the radial stress in the cement sheath but it can significantly increase the shear stress. We found that the risk of cement failure may reduce by making casing string more centralized, increasing the thickness of casing. The results provide insights for design practices led to better integrity in shale gas wells.
In order to get a full petrophysical evaluation from log-based traditional techniques in every location, the formation density is needed in wire-line log measurements; otherwise, with a limited amount of information in terms of porosity values, the reservoir characterization has more uncertainty. That is, the case study of the giant Bachaquero-02 reservoir, there is a lack of Rhob data in the spatial data sets that prevent a good assessment of the storage capacity in the petrophysical model and thus wrong original oil in place estimation. This paper, therefore, presents a solution to this problem; this work develops a methodology for predicting formation density values which establish a link between probabilistic interpretations from multi-mineral solution and deterministic predictions from multiple linear regression with the main objective of seeking a mathematical expression which describes the best fit for the Bachaquero Member and Laguna Member in each location.
The manner of estimating formation density can vary according to the available data in well logs, as a first step, this technique uses classic lithology indicators from well logging such as gamma ray, spontaneous potential and resistivity index to calculate the most probable minerals in the rock with the purpose of assessing a probabilistic approach, the second stage is to create a prediction model with surrounding wells, the input data, which is the probabilistic outcome and measured logs, it is trained using a ‘least squares’ regression routine that will find the best fit in the data for bulk density reckoning.
A reliable formation density profile according to the lithology of the reservoir was obtained for each well. The model shows more than 0.9 of correlation coefficients between the density measured by wire-line services and the new bulk density reproduced in this method. Particularly, the Bachaquero-02 reservoir has a notorious heterogeneity along the stratigraphic column; the Bachaquero Member has different depositional environment and rock properties in comparison with Laguna Member which has poor quality reservoir rock. This workflow has the ability to incorporate reservoir heterogeneities in the probabilistic module without a problem.
Jin, Fu (CNPC Engineering Technology R&D Company Ltd.) | Shunyuan, Zhang (CNPC Engineering Technology R&D Company Ltd.) | Bingshan, Liu (CNPC Engineering Technology R&D Company Ltd.) | Bo, Li (CNPC Engineering Technology R&D Company Ltd.) | Lisheng, Chen (Baoding Second Chemical Engineering Factory)
As a kind of methodology to develop coalbed methane in China, RMRS (Rotating Magnet Ranging System) has been popular in SAGD operation in recent years. In Liaohe Oilfield SAGD (Steam Assisted Gravity Drainage) is becoming a more and more mature methodology. In a pair of parallel wells high pressure steam is injected into a horizontal well to drain heavy oil into the lower production well. However, not all thermal resources have not been exploited, such as heat of the hot production fluid, flue gas and hot brine separated by the steam-water separator in the boiler.
Trials and researches were finalized on many dual-horizontal wells in Liaohe Oilfield to learn about the present situation and technical capabilities, while thermodynamic models of various types were established and experimental means were applied to analyze thermal distribution and each of the thermal sources previously mentioned. Effects of various media, flow rates and temperatures on thermal utilization and heat deficit rates were studied on the assumption that one ton crude oil was produced per hour.
Waste heat of flue gas may be utilized to help combust air and the thermo-coil may be used as the air preheater, which improves boiler’s heat efficiency. The high temperature production fluid may be used to heat water in the boiler first and then used as the heat source of the absorption heat pump, so that heat is transferred from the low temperature heat source to the high temperature heat source and the low grade heat energy is recycled. As a high grade waste heat, the HPHT brine that is separated from moist steam in the boiler takes up twenty percent of the total water and shall not be only used to heat injected water. Instead, it may be used to achieve flash evaporation. Thus, waste water is heated and distilled water is recycled.
The waste heat recyling model applies thermo-coil air preheaters to recycle flue gas and flash evaporated hot brine to evaporate waste water. Beside, hot production fluid is recycled to heat boiler water. On a basis of the same fuel consumption volume, the recovery rate and marketability of crude oil are both improved.
Successful delivery of oil and gas development projects are measured against the promise of an expected production outcome, delivered safely within a scheduled time and budget. This promise is generally based on production forecasts and cost/schedule estimates, with the aim to incorporate the impact of risks and uncertainties on the project. While there are established methodologies for incorporating uncertainties into production forecasts and risks into cost and schedule estimates, there is no established methodology for quantifying the impact of subsurface, drilling or operational risks on production forecasts within foreseen range of cost and schedule. As a result, these risks are often either ignored or incorrectly accounted for as an arbitrary percentage discount on forecasted volume. The objective of this paper is to propose a clear methodology to categorize, quantify and incorporate these risks in forecasts, provide a basis for robust production forecasting and drive better business decisions.
Three main risk types are defined in this methodology under two categories: Execution risks and Operational risks. Execution risks are defined as the risks occurring at the time of execution comprising of Subsurface and Mechanical risk types. Subsurface risk is probability that the encountered subsurface outcome is poorer than considered in the uncertainty ranges, e.g. depleted, swept, compartmentalized or with unexpected fluids/contaminants. Mechanical risk is the probability of unsuccessful drilling, completion or intervention of the well as per the development plan, e.g. due to borehole collapse, well loss or completion failure. Operational risks exist throughout the production lifetime and are defined as the probability of premature failure of the well or shut-down of the facility before producing its Estimated Ultimate Recovery (EUR), due to completion failure, well and facility integrity challenges.
The Execution risks are expressed as Chance of Success (CoS) against the risk and modelled using a Bernoulli distribution. The Operational risks are defined using a CoS and a distribution function derived based on statistics of historical failures observed in regional/analogous field(s). The risks are rolled-up in a probabilistic decision tree analysis along with the low, mid and high subsurface outcomes. The P90, P50 and P10 cases are identified from multiple realizations based on production rates and EUR outcomes, and deterministic equivalents of each outcome are selected based on possible scenarios.
The Development Well Risking methodology incorporates multiple risks into production forecasts, and introduces a more robust approach towards forecast adjustments across the industry. Furthermore, the methodology is used to better evaluate competitive scopes and assist with decision making processes. The risking also provides a basis for justification of base protection projects or activities that de-risk base case production but provide no direct incremental value/volumes, while require cost expenditure. The methodology can be implemented into integrated subsurface, surface and economic analysis workflows in evaluating Expected Monetary Value (EMV) to ensure an integrated outcome is achieved.
Primary gas recovery for a volumetric reservoir ends when the reservoir pressure declines below the value required to flow gas to the surface at the sales line pressure. Secondary gas recovery techniques can then be employed to increase the recovery, once they are economically viable. The most common of these techniques is gas compression; but another feasible technique, which is rarely ever explored, is water injection. This paper evaluates the incremental benefit of water injection in a conventional gas reservoir when compared to gas compression.
This was achieved through analytical simulation of a retrograde gas-condensate reservoir located in the Columbus Basin off the south-east coast of Trinidad. The techniques which were applied here have been historically used in the waterflooding of oil reservoirs, and were tailored in this novel case for the use in gas reservoirs. The reservoir evaluated is a faulted sandstone formation of good quality that is divided into two hydrocarbon bearing segments. In one of the segments, production ended due to a decline in the reservoir pressure, indicating the end of primary gas recovery. Both reservoir and well modelling were done using the IPM Suite. In this paper, the scope was narrowed to focus on the application of analytical simulation as a means of quickly screening various production scenarios. Simple economic evaluations were done using the University's methodology and current economic metrics, with the operational and capital expenditures derived from offshore projects by operator companies within Trinidad.
The findings showed that while gas compression generated significantly higher internal rates of return, water injection provided similar net cash flows. Unlike gas compression, which improves the recovery by allowing the reservoir to produce at a lower tubing head pressure than the sales line pressure; water injection increases the reservoir pressure by filling the voidage space created as a result of the depletion process. Thus, the feasibility of water injection is dictated largely by the volume of water which is required, since gas is highly compressible.
The primary value of water injection as a secondary gas recovery technique stems from the use of high water rates from nearby producing wells under aquifer drive, which would otherwise be shut-in. The technique can also be managed as a water disposal option for adjacent fields, thus reducing company expenditure on treating the produced water from the wells mentioned above.
Design a completion system for sand control based on top technology as an alternative to the slotted-liner completions systems currently installed in extra heavy oil producing wells in unconsolidated formations.
The methodology and design are based on the resulting interpretations of Dry Sieve Analysis (DSA), Laser Particle Sieve Analysis (LPSA), and geological considerations. Based on the results of these analyses, uniformity coefficients were calculated and grain size sorting results were used to validate the completion criteria, the system type, and the open area to be used. Once these criterions were selected, the Sand Retention Test (SRT) was utilized in the laboratory to verify the performance of the design using different liner sections and core plugs specific to the area; which allowed the selection of the appropriate system. Quantifying the total recovered barrels with the new completion system was done using a nodal analysis in order to evaluate the cost benefit in a typical well.
As result of the interpretations of the tests, it was determined that the open area size of the completion system should be 200 μm, being estimated by the D10 obtained by the DSA realized to the core "A" of the Lower Morichal Formation. With the LPSA realized to the core "B", the quantity of thin grain movables less than 45 μm was estimated for the Lower Morichal Formation. All of these criteria were unified to select the completion method best suited for sand control. The results shows that the best option is metal mesh screen, which offer 150% more flow area in comparison with the slotted liner which translates to a recovery of 10% in production according to nodal analysis simulations.
While current design practices sometimes take into consideration grain size distribution and sorting, this paper highlights the added benefit of combining this approach with the laboratory results of the DSA and LPSA testing methods to ensure that production recovery is truly maximized.
Sun, Fengrui (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum) | Yao, Yuedong (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum) | Li, Guozhen (China University of Petroleum) | Zhao, Lin (China University of Petroleum) | Liu, Hao (China University of Petroleum) | Li, Xiangfang (China University of Petroleum)
Most of the previous works were focused on the saturated/superheated steam flow in wellbores coupled with conventional single-tubing injection method. With the rapid development of technology. Supercritical water coupled with toe-point injection technique is proposed.
Compared with conventional method, supercritical water could heat the reservoir to a higher temperature, obtain a larger heated radius, and obtain a higher thermal cracking efficiency etc. Besides, toe-point alternating heel-point injection could release the phenomenon of unequal absorption of steam when the horizontal wellbore is extremely long or the reservoir is of serious heterogeneity.
This paper presents a model for estimating thermal properties of supercritical water along the inner tubing (IT) and annuli in the horizontal section of the wellbores with toe-point injection technique. Firstly, a flow model in wellbores is proposed based on the mass, energy and momentum conservation equations. Secondly, coupled with flow model in reservoir, a comprehensive mathematical model is proposed. Thirdly, type curves of supercritical water flow in horizontal wellbores with toe-point injection technique is obtained by finite difference method on space and iteration technique. Finally, sensitivity analysis is conducted.
Results show that: (a) supercritical water temperature decreases rapidly from heel-point to toe-point in IT. The temperature decrease rate near toe-point of wellbores becomes smaller. (b) The larger the pressure difference, the larger the mass injection rate from annuli to oil layer. (c) When the mass injection rate is small, heat loss from fluid to reservoir plays an important role on temperature drop. (d) When the injection rate is high enough, the effect of heat loss on temperature drop becomes weak. (e) The pressure of supercritical water at a certain place in IT or annuli decreases with injection rate.