bluuebunny/crossref_metadata_2025 huggingface dataset:
Sabriyah Lower Burgan Field EOR Development Study: Use of Sacrificial Wells to Minimize Water Encroachment
Authors: Al-Murayri Mohammed Taha , Al-Mayyan Haya Ebrahim , Al-Ghnemi Mohammad Faleh , Pitts Malcolm , Dean Elio , Wyatt Kon , French Josh , Skeans Elii
Published: March 2019

Sabriyah Lower Burgan (SALB) is a multi-billion-barrel reservoir located in north Kuwait with favorable fluid and rock properties, and a strong active aquifer. The presence of the aquifer is advantageous for primary development of the reservoir but presents a challenge for conventional application of chemical EOR (CEOR). SALB has passed multiple stages of a CEOR evaluation process (technical screening, laboratory formulation design, SWCT, pilot design, risk assessment, etc.), and is currently considered for a multi-well CEOR pilot. This study investigates the viability of using sacrificial wells in the management of the lateral aquifer present in the SALB Layered formation, which represents a sought after CEOR target. The objective of these sacrificial wells is to reduce the potential negative impacts of the existing aquifer on commercial CEOR deployment.

The adopted approach involved using a history matched field model with EOR parameters calibrated to laboratory results for ASP and CO2 technologies. The multi-well field model was used to evaluate and compare different development scenarios to assess the impact of sacrificial wells. These scenarios were evaluated based on production performance and economics.

It was observed that strong aquifer presence complicates both CO2 and ASP project implementation. Challenges due to the aquifer include loss of EOR agents into the water leg, difficulty in accounting for effective pore volume of the project and water encroachment. It is difficult for EOR project economics to compete with an effective aquifer primary development. Sacrificial wells can be used to reduce the strength of the aquifer, potentially improving the effectiveness of the EOR technology. Although the sacrificial wells are unlikely to be economic on their own, they can improve the overall economics of the project. The amount of recovered oil due to EOR deployment is an important parameter to evaluate the economic feasibility of using sacrificial wells.

Many reservoirs around the world have strong aquifers, for which conventional reservoir engineering advice has been to avoid EOR application. This paper introduces a novel approach to deal with these strong aquifers by strategically placing wells that can reduce the aquifer's strength, thus making EOR deployment more favorable.
Comparative Study of the Mechanical Properties of Reduced Density Cements
Authors: Deshpande Abhimanyu , Jones Paul , Jadhav Rahul , Pangu Ganesh , Mishra Vaishali
Published: March 2019

Cementing a casing string across weak formations or depleted reservoirs has the added challenge of tailoring the cement slurry to meet delivery criteria (i.e., density and rheology) while maintaining the mechanical properties of the set cement necessary to provide a dependable barrier. To help prevent fracturing the formation and inducing losses, cement density is often reduced, which strongly influences the mechanical properties of set cement. Common strategies for reducing cement density consist of adding water in the cement slurry; using additives such as hollow glass microspheres (HGS), synthetic latex, and elastomers; using foam cement; or adding resin. This paper discusses how cement slurries with reduced densities are designed using both traditional and alternative methods of making cement/resin composites and provides insight into the advantages and drawbacks of each.

Stable cement slurries with a density of 13 lbm/gal were designed, and placement characteristics of thickening time and rheology were evaluated for the liquid cement slurry. Unconfined compressive strength (CS), Young's modulus (YM), tensile strength, permeability, and shear bond were investigated on the cured samples. Before taking mechanical and permeability measurements, slurry stability was verified using sedimentation testing. Any slurry that did not exhibit the necessary stability was redesigned and tested again. Only the final slurry designs exhibiting stability are discussed in this paper.

Cement-resin composite cements exhibited similar performance to those containing HGS in terms of CS, YM, tensile strength, and shear bond but exhibited greater than two times the CS when compared to the synthetic latex modified, water-extended, and elastomeric slurry designs. The cement-resin composite provided almost twice the shear bond strength and increased tensile strength by 50% compared to other slurry compositions.

In the current work, cement-resin composite, synthetic latex modified, microbead-based, water-extended, and elastomer-modified slurries are compared at 13 lbm/gal. Various parameters, such as mixability, ease of placement in the annulus, strength development, and long-term cement integrity, are evaluated. Traditional and newly introduced techniques for reducing cement slurry density and the resultant mechanical properties of the set solids are investigated. This information provides an alternate method of using cement-resin composites for designing and delivering dependable barriers tailored for low density applications.
Effective Geomechanic Approach for Wellbore Stability Analysis
Authors: Alsiyabi Kuthar , AL-Aamri Mohammed , Siddiqui Numair Ahmed
Published: March 2019

The success of drilling operations strongly depends on proper mud weight design. In fact, unsuccessfully optimizing the mud weight could lead to wellbore collapse. Within the oil industry, Mogi and Mohr-Coulomb models are the most-practiced failure criterion used in predicting critical mud weight.

This paper was aimed at inspecting these models regarding mud weight prediction. A new comparison concept was also developed. Furthermore, the different stochastic perspectives were carried out in the study. Based on field data, the required mud weight was found using the Mogi and Mohr-Coulomb failure criteria. The results suggested that the predicted pressure from the Mogi model is considerably close to the real mud weight. The study is also developed using the new pragmatic comparison criteria called the breakout width.

The predicted mud weight from both models was separately utilized to obtain the width of shear failure (breakout) by applying the simple analytical model. The results revealed the breakout dimension was a bit over-predicted with respect to the Mohr criteria. Moreover, the optimum mud weight was a function of input parameters, which include stresses and rock properties.

The knowledge of such parameters depends effectively on the quality of the parameters. The deterministic approach was presented to display the influence of each parameter by developing tornado diagrams. The analysis was defined that the maximum horizontal stress is the most influential parameter for collapse pressure prediction for both models. In addition, overburden stress has a considerable effect on the Mogi model and was ignored in the Mohr criteria. Other parameters were also captured in the analysis. In this paper, the probabilistic analysis approach using Monte Carlo simulation was also implemented into wellbore stability models to cover all the significant parameters with their uncertainties rather than certain values for improving predictions. Based on the analysis, the mud weight optimization will have a direct impact on future drilling practices and operation costs.
Detailed Comparison of Processed Sand vs. Unprocessed Sand vs. High-Strength Proppant for Fracturing Applications
Authors: Shakeel Muzzammil , Abdulrazzaq Waseem , Abdullatif Osman , Benaafi Mohammed
Published: March 2019

A detailed study comparing various properties and attributes of local Saudi Arabian sand (processed and unprocessed) and high-strength proppant (HSP) for hydraulic fracturing applications is discussed. Further, quartz grain crystallinity, texture, quality, and mechanical durability (strength) are described and an insight into the prospects of sand application viability during hydraulic fracturing is provided.

An in-depth comparison of processed sand, unprocessed sand, and readily available HSP widely used in the industry was performed. It is well known that the Middle East region, particularly Saudi Arabia, has an abundance of sandstone formations ranging from the Cambrian to Quaternary age; outcrops of these formations extend from northern to southern parts of Saudi. These formations have varying grain sizes and other physical attributes that must be studied to grade their possible performance as hydraulic fracturing proppants. Unprocessed sand samples were collected from various central and southern Saudi sandstone formations. Petrographic analysis, including thin section and scanning electronic microscopy (SEM), was conducted on sand samples to quantify the percentage of polycrystalline quartz grains and define their surface features. Crush-resistance testing was performed on the samples to compare the mechanical durability of the sands and HSP.

The results of this study confirmed that polycrystalline quartz grains are more abundant in coarse-grained sandstones than those fine-grained. Mechanical durability decreased with an increased percentage of polycrystalline quartz grains, strained grains (with undulose extinction), and surface features. The metamorphic nature of the quartz grain source rock and intense chemical weathering along the quartz grain surface reduce its strength. HSP demonstrates greater mechanical durability compared to processed and unprocessed sand, keeping in mind, the processed sand was from a specific sandstone formation.

The suitability of Saudi sandstones for the petroleum industry's use is dependent on the mechanical durability of quartz grains, which, in turn, depends on the source and chemical weathering of those grains. Comparatively, HSP is more durable and mechanically strong; however, processed sand has an edge over unprocessed sand.
Reframing Exploration Workflows for Small to Super-Merge 3D Seismic Interpretation
Authors: Taylor David , Ali Sadaqat
Published: March 2019

Techniques for 3D seismic interpretation by geoscientists are continuously undergoing improvements, and future exploration is anticipated to continue to benefit from high-confidence first pass interpretations utilizing all of the available seismic and well data. Workflows have been developed on a ‘super-merge’ 3D volume to produce attribute-enhanced chronostratigraphic stratal surfaces, allowing interpretation of regional-scale seismic facies and associated seismic geomorphology and tectonostratigraphy.

In this example, a semi-supervised machine-based learning workflow has provided rapid turnaround interpretation of the structural framework and chronostratigraphy throughout the entire 3D seismic volume, maximizing the value of the seismic information. This workflow consists of a three-step auto-tracking workflow to build a Relative Geological Time (RGT) geo-model directly from the seismic volume. This enables more time to spend on geological validation and interpretation of the stratal surface seismic geomorphology. Study results have provided the foundation for rapid turnaround well and seismic integrated play fairway maps; a powerful tool for stimulating exploration in mature areas or wildcat acreage assessment.

This study focused on Middle and Upper Jurassic carbonates deposited on a broad low angle platform on the Arabian Plate. Interpreting in map view on RGT constrained stratal surfaces with attributes such as, relative acoustic impedance and spectral decomposition, is invaluable for visualization since the stratal surface follows the morphology of the imaged geologic features. The ability to select any stratal surface within the volume and flatten, either on a seismic display or the Relative Geological Time geo-model, is particularly useful to establish the timing of major tectonic episodes and accommodation space fluctuations.
ASP Flood Application for a High-Temperature, High-Salinity Carbonate Reservoir
Authors: Abalkhail Nassir A. , Liyanage Pathma J. , Upamali Karsinghe A. , Pope Gary A. , Mohanty Kishore K.
Published: March 2019

The goal of this work was to develop a highly efficient alkaline-surfactant-polymer (ASP) process applicable to a high temperature (~100 °C), high salinity (~60,000 ppm) giant carbonate reservoir with very low surfactant retention, an essential requirement for low chemical cost. Phase behavior tests were conducted with anionic surfactants, alkali, co-solvents, brine, and crude oil to identify chemical formulations with ultra-low IFT under reservoir conditions. Corefloods were first conducted in outcrop carbonate cores and then in reservoir cores. The effluent was analyzed for oil, surfactant, pH, salinity and viscosity. Pressure drop was monitored across 4 sections of the core to monitor front propagation. Surfactant adsorption on carbonate surfaces decreases at high pH. The conventional alkali used for ASP floods of sandstones is sodium carbonate. However, sodium carbonate cannot be used in formations containing anhydrite, which is the case for the target reservoir. For this reason, ammonia, sodium hydroxide and a new organic alkali were studied for this application. Ultralow IFT (~0.001 dynes/cm) was achieved with several ASP formulations using the reservoir oil. Coreflood experiments using both outcrop limestone and carbonate reservoir core were conducted using these alkalis. The coreflood results showed good oil recovery and low surfactant retention.
A Closer Look on Viscosity and Divergence Effects of Gel Treatments in Fractured Systems
Authors: Alshehri Amar J. , Wang Jinxun , Kwak Hyung T. , AlSofi Abdulkarim M.
Published: March 2019

Polymer gel treatment is a successful technology for conformance improvement. Achieving effective deep conformance control in high-temperature reservoirs requires improving the performance of gel in these environments and a deep understanding of gel-conformance control mechanisms inside reservoir rocks.

In this work, a laboratory study was conducted to evaluate a polyacrylamide/chromium gel system for a carbonate reservoir at high-temperature and high-salinity (HTHS) conditions. Displacement experiments combined with nuclear magnetic resonance (NMR) measurements were performed to investigate the mechanisms of conformance treatment as well as demonstrate the potential of oil production improvement by a gelling system. Coreflooding tests were performed on carbonate core samples with different configurations of high-permeability channels. Both gel treatment and polymer flooding experiments were conducted to quantify and differentiate between fluid-diversion and viscous effects on oil production improvement due to the treatment. Detailed spatial fluid variations inside the core samples before and after gel treatment were closely monitored using low-field NMR techniques.

Both coreflooding experiments and NMR measurements clearly showed that significant oil production improvement was achieved by gel treatment. The bypassed oil during waterflooding was effectively mobilized. Gel treatment is more efficient in oil production improvement for more heterogeneous core samples. The comparison study of gel treatment and polymer flooding helps gain insight into the mechanisms of oil displacement.

Results show that the blockage or fluid-diversion effect plays a more significant role in oil production improvement after gel treatment. The viscous effect of gelant flow helps mobilize oil in the matrix region. The oil production improvement by gel treatment is mainly attributed to the fluid-diversion effect, especially for the treatment in high-permeable configuration. Moreover, results of the study demonstrate the potential of the studied gel system for carbonate reservoirs at high temperature. NMR techniques add additional valuable information to conventional displacement tests to identify the dominant mechanisms of oil mobilization.
Pour Point Depressant Treatment via a Field-Deployable Performance Monitoring Technology
Authors: Zheng Sheng , Patel Nimeshkumar , AbouZour Mohamed
Published: March 2019

Waxy crude oils are commonly encountered by oil producers. Wax precipitation and the subsequent wax deposition and/or pipeline gelation are common flow assurance issues associated with crude oil production and transportation. Pour point depressants (PPD) and wax inhibitors (WI) have been proven successful in preventing gelation and mitigating deposition. However, for many reported cases, due to the lack of effective field-deployable performance monitoring technologies, PPD applications have failed to address undesirable changes in field conditions, i.e. increased pressure drop, change in fluid composition, equipment failure etc., in a timely fashion. Utilization of a field-deployable technology will allow a quick and accurate crude treatment via a suitable PPD application. This paper presents a field-deployable technology for wax risk assessment and PPD treatment monitoring. The technology is based on the characterization of the molecular interactions between paraffin chains and PPD additives using Fourier-Transform Infrared (FTIR) fingerprinting. The oil fingerprinting and data analytics can be utilized to predict the wax appearance temperature, pour point and wax deposition potential of the oil. Two polymeric pour point depressants were studied and their remarkable performance and handleability are reported.
A New Tool for Identifying Unconformities During Exploration Drilling
Authors: Ryan James , Roberts Richard
Published: March 2019

A powerful new tool for unconformity identification in a range of geological environments is presented together with very strong evidence of its utility.

Commonly in an exploration setting correct sequence interpretation has taken years and multiple detailed studies, now with the new tool it can be done quite easily in near real time.

Recognition of unconformities in boreholes, particularly where correlation with outcrop is not available, traditionally relies on paleontological methods, normally palynology or micropalaeontology and correlations between wells where sections of the observed sequence are missing. Observations in recently drilled wells in Dubai have provided evidence for another useful tool.

While drilling Well A, bulk rock phosphate concentrations were obtained in near real time while drilling using X-ray fluorescence (XRF). These were then plotted against well depth. Phosphate values were taken as indicators of long duration and high intensity of organic production or conversely a low rate of sedimentation. Unconformities were marked by significant and obvious phosphate peaks while drilling in a marine sequence. Higher than average concentration of phosphates in marine environments during periods of non-deposition or very slow deposition have been known for some time but their use as markers for unconformities while drilling has not been widespread due to the practical difficulties with sample analysis. With advances in XRF technology routine wellsite XRF analysis services are now available.

Plots of phosphate concentrations in Well B which was drilled through a sub-aerially deposited sequence also showed phosphate peaks, some of which correlated with known and recognisable unconformity surfaces. Further evaluation, particularly comparison with palynology data, showed that the phosphate peaks which did not correlate with known unconformities indicated previously unrecognised unconformities. Phosphate peaks on unconformity surfaces in sub-aerially deposited sequences have not, as far as the authors can determine, been previously recognised.

Well C is an older well which penetrated a similar sub-aerially deposited sequence to Well B with no XRD analyses available. Correct interpretation of the Well C sequence was not possible until the key points were derived from the more complete Well B data.

Evidence is presented showing that phosphate peaks are practical and useful indicators of unconformities in near real time, especially when interpreted with other geological information. An example is also given of an unconformity which displays no phosphate peak together with an explanation as to why there is no peak.

In an exploration setting analysis of phosphate trends can significantly enhance and simplify sequence and palaeoenvironmental interpretation and understanding of regional tectonics thus providing greater insight when planning follow up wells leading to a higher success rate. As such it is a new and novel exploration tool with a potentially high economic value.
AccuPipePred: A Framework for the Accurate and Early Detection of Stuck Pipe for Real-Time Drilling Operations
Authors: Magana-Mora Arturo , Gharbi Salem , Alshaikh Abrar , Al-Yami Abdullah
Published: March 2019

Thorough preplanning and best drilling practices are effective in reducing stuck pipe incidents, data analytics offer additional insight into further reducing the significant non-productive time (NTP) that results from this unplanned event. The severity of the stuck pipe problem may stop the drilling operations for a short time, or in more difficult cases, the drill string has to be cut and the borehole is sidetracked or plugged and abandoned. Consequently, detecting the early signs of this problem, in order to take the right actions, may considerably or entirely reduce the risk of a stuck pipe.

Although computational models have been proposed for the early detection of the stuck pipe incidents, the models are derived from a reduced set of wells with stuck pipe incidents, which may result in under-trained models that predict a large number of false positive alarms. A sufficient amount of data or wells that statistically represent the parameters surrounding stuck pipe incidents under different circumstances is required in order to derive a generalizable and accurate prediction model. For this, we first derived a framework to automatically and systematically extract relevant data from the historical data. As such, our framework searches through the historical data and localizes the surface drilling and rheology parameters surrounding the stuck pipe incidents. Moreover, we performed feature selection by selecting the top-ranked parameters from the analysis of variance, which measures the capability of the drilling and rheology parameters to discriminate between stuck pipe incidents and normal drilling conditions, such as, weight on bit, revolutions per minute, among others.

Using the relevant features selected by the analysis of variance, we derived a robust and fast classification model based on random forests that is able to accurately detect stuck pipe incidents. The implemented framework, which includes the automated data extraction module, the analysis of variance for feature selection, and prediction, is designed to be implemented in the real-time drilling portal as an aid to the drilling engineers and the rig crew in order to minimize or avoid the NTP due to a stuck pipe.
Numerical Approach in Analyzing Pressure Transient Responses in Dual-Porosity Dual-Permeability DPDP Reservoirs
Authors: Alramadhan Aymen A. , Guerrero Rodolfo J. , Alzahrani Abdulrahman M. , Al Awami Bassam A.
Published: March 2019

Advancements in numerical well testing packages in interpreting pressure transient behavior of complex well geometries and reservoir structures have lead to an improved understanding of the multi-scale heterogeneity encountered in dual-porosity dual-permeability (DPDP) reservoirs. This paper demonstrates the power of numerical well testing models in handling conceptual cases of increasing complexity in dual-porosity dual-permeability (DPDP) reservoirs where a high permeability matrix system interact with super-k intervals, fractures, and faults systems with different levels of complexity.

Numerical well test models are built using data from multiple scales and sources (image logs, flowmeter responses (PLTs), petrophysical logs (FALs), and seismic attributes) to match pressure transient responses of wells completed in dual-porosity dual-permeability reservoirs. Six generalized conceptual cases are presented in this paper; a vertical power water injector that initiated induced fractures due to injection above fracture pressure, a vertical well near an area of intersecting faults, a 40-degree deviated well intersecting diffuse fracture network, a deviated well near a conductive fracture corridor, a horizontal well intersecting a finite conductivity fracture, and a horizontal well intersecting an infinite conductivity fracture. An integrated approach was used to match the pressure responses in all cases.

Experience shows that the most representative well test solution comes from a thorough integration of well-test data with all available static and dynamic data (e.g. image logs, flowmeter responses (PLTs), geophysical, and petro-physical data). In addition, inclusion of pressure transient responses of offset wells in the area understudy as part of the analysis is crucial in choosing the most representative well test model.

In summary, this paper provides guidance and best practice to reservoir engineers in building numerical well test models to analyze fracture and matrix responses in dual-porosity dual-permeability (DPDP) reservoirs. Conceptual cases emphasize integration of multiple sources of static and dynamic data to model different well responses.
Back-to-Basics Gives New Lease on Life to a Reservoir
Authors: Bardalaye Jayanta , Salem Salah , Al Ghani Sayed , Al Sadadi Ahmed , Nedham Najla
Published: March 2019

The onshore Bahrain Field is a multi-reservoir oil and gas field in the Kingdom of Bahrain. Hydrocarbons are found in various stratigraphic intervals from Devonian to Upper Cretaceous in mostly carbonate reservoirs. Clastic reservoirs are scarce in the post-Permian section but dominate in the pre-Permian section. The Lower Cretaceous Kharaib Limestone is an oil reservoir. The unit was tested in different exploratory wells in the early life of the Bahrain Field and it was found to be of low permeability but produced oil.

The first phase of field development in Kharaib was initiated in the 1970s and after an initial period of dry oil production, the wells produced for a long time with high water cut (more than 90%). In the early 2000s, a horizontal well drilled in the reservoir provided encouraging results. Main development activities started from 2010 onwards, after Tatweer Petroleum – Bahrain Field Development Company W.L.L. ("Tatweer Petroleum") was formed. Thirty horizontal and fifteen deviated producers (a total of forty-five wells) were drilled during the period 2010–2014 and as a result, oil production from the reservoir increased significantly. However, within a short period of time, most of the wells started producing with high water cut (more than 90%) and image logs recorded in many horizontal wells showed presence of fractures. Based on this observation and 3D seismic analysis, Kharaib was characterized as a fractured reservoir and high water production was attributed to it. Later on, many wells had mechanical failure due to casing corrosion developed against the shallower Shuaiba aquifer. All development activities were subsequently stopped for the reservoir due to economic risk.

In 2016, a renewed effort was undertaken to analyze all past data including; regional tectonics, core data, 1970s build-up studies, cement integrity, and image log interpretations. This back-to-basics analysis indicated that the primary cause of high water production in the Kharaib wells is lack of zonal isolation with Shuaiba (casing corrosion wells excluded) and not due to the presence of occasional fractures.

Development activities restarted in 2017 that focused on addressing the zonal isolation and casing integrity issues. Seven wells have been drilled to date producing with an average water cut of 22%. More development wells are planned in the future thereby giving a new lease on life to the reservoir.
Investigate Proppant Transport with Varying Perforation Density and its Impact on Proppant Dune Development Inside Hydraulic Fractures
Authors: Ba Geri Mohammed , Imqam Abdulmohsin , Suhail Mohammed
Published: March 2019

Proppant transport adequately during hydraulic fracturing treatment assumes same perforation contribution through multi-perforation system. Proppant transport performance into the different ordination fracture system using multi-entry perforation technique is still not fully understood. This experimental study was aimed to deeply investigate five factors that affect proppant transport performance: number of perforations, perforation opening size, shear rate, fracture orientation, and proppant size distribution. The impact of these factors on proppant transport performance from different perspective was studied. Fracture slot model was designed and built to observe easily the effects of perforation density and fracture orientation. The results of this experimental work show that limited-entry perforation technique has significant impact on proppant transport within fractures where single top perforation had better proppant placement than multi-perforation system. Fracture area was approximately propped with 66% and 48% using top perforation and multi-perforation system, respectively. Slurry with high shear rate has a negative effect on the proppant equilibrium dune level (EDL) and fracture propped area (FPA). Fracturing treatment using high shear rate causes high pressure drop in the fracture that leads to decreasing EDL by 17% and fracture propped area by 23% comparing to using low shear rate. Using large proppant size (20/40) leads to form high EDL and FPA compared to 100 mesh size. Proppant transport dominated by four mechanisms and the vertexes near wellbore plays main mechanism to carry proppant farther inside the fracture.
A Novel Method for Characterizing the Dynamic Behavior of Proppant Pillars With Fracture Closure in Pulse Fracturing
Authors: Lu Cong , Li Zhili , Zheng Yunchuan , Yin Congbin , Yuan Canming , Zhou Yulong , Zhang Tao , Guo Jianchun
Published: March 2019

The pulse fracturing is widely used in unconventional reservoirs. It alternately pulse pumping the proppant slurry and clean fluid to form discontinuous placement proppant pillars in the artificial fractures and the pulse fracture conductivity is several orders of magnitude higher than conventional hydraulic fracture conductivity. However, the understanding of the deformation law of proppant pillar under the action of closure pressure and proppant normal stress is unclear, resulting in difficult to calculate the fracture conductivity and prefer proppant.

Firstly, replacement construction and experimental displacement by Renault Similarity Criteria, three typical proppant pillars placement structures are extracted through the large-scale visualized flat plate device. The Young's modulus of the proppant pillars are calculated in modified API conductivity cell. Secondly, proppant pillars are dispersed into particles by the Smooth Particle Method (SPH). Using the parameters obtain from the above experiments, fracture-proppant pillar contact models are established to simulate the deformation process of proppant pillar and get normal stress of proppant particles. Thirdly, extracting the shape of stabilized proppant pillars, establish the fracture-proppant pillar flow model, calculate the fracture conductivity in different closure pressure.

The simulation results show that as the closure pressure increases from 14MPa to 41MPa, the fracture width present an accelerated downward trend, The fracture width under the support of the initial radius of 9 mm proppant pillars are the largest, decreasing from 2.52mm to 1.72mm, the larger the radius of the proppant pillar, the greater the fracture width, the normal stress of three types of proppant pillar particles are both changed from 73MPa to 110MPa. The elliptical cylinder proppant pillar has the largest fracture conductivity. Its fracture conductivity is reduced from 12500D•cm to 3630D•cm. The larger the construction displacement and the pulse time of proppant slurry, the greater the fracture conductivity.

The model in this article can calculate the normal stress of proppant particle and fracture conductivity in different closure pressure, which can significantly guide the choice of construction parameters and the type of proppant.
Production Logging Using Quantum Dots Tracers®
Authors: Anopov Alexey , Ovchinnikov Kirill , Katashov Alexander
Published: March 2019

Conventional production logging tools proved to be efficient in vertical wells. When it comes to work in horizontal laterals production logging becomes much more complex. Common challenges are layered flow of reservoir fluid, deviation, wellbore accessibility, and stagnant zones along lateral. The tracer technology features a synthesis of a combination of marker-reporters made of a few quantum dots and a mixture of the polymer-based chemical composition. Quantum dots are nanocrystals produced using the process called colloidal synthesis. A single quantum dot is compounded of few hundred atoms and as small as 2-10 nanometer in diameter. Colloidal quantum dots irradiated with a laser emit light of different colors due to quantum confinement. The emittance of a particular specter of light can be detected using flow cytometry method. Several quantum dots joined together creates a unique and traceable marker-reporters element. There could be many unique tracer signatures (over 60). Utilization of quantum dots exclude any chance of misinterpretation while identifying tracers in samples of formation fluid. To achive superior accuracy in tracer identification we use software based on "machine learning". Qualitative and quantitative analysis of quantum dot marker-reporters in samples of formation fluid allows making informed conclusions about the performance of productive intervals of a horizontal well. Application of the technology showed the following benefits: the possibility of monitoring inflows for a long time, in contrast to a one-time logging operation; a significantly lower resource intensity and cost; confidence in conditions when the traditional downhole logging operations are complicated. Quantum dot tracer technology allows solving a number of problems, such as: post-fracturing inflow profile evaluation extended in time; assessment of each production interval in regard to water and oil production; optimization of technical solutions for well completions in the early stages of field development, such as number of ports; analysis of hydrocarbons extraction ratio; detailed information in the analysis of mutual influence of neighbouring wells in the oilfield. The application of the technology is particularly effective in the early diagnosis of water breakthrough, which allows enough time to choose the right technology for water shut off operation. Ultimately, this fact reflects in declining production rates and increasing incurred costs Major benefit is an ability to monitor production per zone at any time during five (5) years after deploying tracer-containing material downhole. Implementation of the technology is time efficient and does not require field equipment as well as crew for operation, which reflects on operating costs carried by customers.
Increasing Efficiencies During Cased Hole Fracturing Operations Through Frac Plug Material Selection
Authors: Wright Beau , Parekh Yash , Casanova Gabriel
Published: March 2019

Plug and Perf (P&P) still remains one of the most prolific methods used in multi-stage hydraulic fracturing operations. Recent changes in the materials chosen to manufacture frac plugs is leading to increased efficiencies during installation as well as the plug milling phase of P&P operations.

Historically, the fluid diversion devises used in multi-stage hydraulic fracturing operations have been manufactured using mainly glass/epoxy based composite materials and in recent years, in an effort to increase efficiencies, disintegrating materials. Most efforts have been focused on reducing the amount of metallic parts as well as reducing the overall amount of material used to manufacture these plugs in an effort maintain plug performance during fracturing operations while reducing time/costs during post-frac milling operations by making plug removal more efficient.

Recent advances in metallic based composite materials are allowing for plugs to be manufactured out of light weight alloys that are higher strength than traditional composite plug materials while also being easier to remove and circulate out during plug milling operations. Also, because the materials are not designed to disintegrate, there is no need to consider fluids that the plugs will be exposed to thus ensuring a high performance plug without the careful balancing act between an environment that causes the plug to disintegrate too fast or not at all. In addition to this, changes in how slips and packing elements are being designed is allowing for additional gains in efficiencies during plug deployment and removal.

Using real-world results, we can now demonstrate how these design changes can allow for a new level of operational efficiencies not previously available in P&P operations.
ASP Flood With Novel Mixtures of Anionic-Cationic Surfactants for High Water Cut Mature Sandstone Reservoir: From Laboratory to Field Application
Authors: Li Yingcheng , Kong Bailing , Zhang Weidong , Bao Xinning , Jin Jun , Wu Xinyue , Liu Yanhua , Wang Yanxia , He Xiujuan , Zhang Hui , Shen Zhiqin , Sha Ou , Yang Weimin
Published: March 2019

Cationic surfactant is never used in Enhanced Oil Recovery (EOR) for negative charged sandstone reservoirs because of high adsorption. Since January 2012, the first field scale application of alkaline surfactant polymer (ASP) flood in the world with thermal stable, highly efficient mixtures of anionic- cationic surfactants (S) for super low acid oils, was carried out in Sinopec for a high water cut mature sandstone reservoir with approximately 8,000 mg/L total dissolved solids (TDS), temperature of 81°C, to demonstrate the potential of this novel surfactants to recover residual oil from as high as 53.3% recovery percent of reserves. The maximal water cut decreased from 97.9% to 90.2%, along with peak daily oil production increased from 23.0 t to 106.1 t. The cumulative incremental oil by ASP flood at the end of December 2018 is about 276.1 kt and the oil recovery was increased by 10.65% OOIP. The estimated ultimate oil recovery can be increased by 14.2% OOIP and yield up to 67.5% OOIP.
Energized Acid Fracturing in Deep Carbonate Reservoirs. CO2 versus N2
Authors: Abel Justin Tate , Idris Muhammad , Choon Hoong Chan , Simbolon Ronny
Published: March 2019

Flowing back initiation for cleaning up process after a fracturing treatment in low-pressure reservoirs are becoming a challenging operation. One of the alternatives is to conduct a post-frac CT intervention using nitrogen to kickoff the flow. This operation is known to be expensive as well as time-consuming. The use of foamed fluids for fracturing operations in low-pressure gas reservoirs would help in facilitating flow- back operations and also minimizing the volume of water pumped to the formation. Nitrogen (N2) and Carbon Dioxide (CO2) are the most common gases used in foam fluids. N2 is an inert gas, and most frequently used. CO2 is more soluble in water than N2, so more CO2 is required to saturate the liquid and create the foam. But CO2 has significant advantages over N2: greater hydrostatic pressure resulting in lower treating pressure; it has more expansion during flow back that aids in total fluid recovery; the solubilized portion of carbon dioxide reduces the interfacial tension of the fracturing fluid. A study to compare the production performance from two nearby horizontal wells conducted where both were stimulated with Foam fracturing using a different gas type.

This paper describes the comparsion of acid fracturing treatment using CO2 and N2. The two wells drilled from the same pad; the horizontal parts section drilled in the opposite direction, both wells completed with OH MSF (Open Hole Multi-Stage Fracturing) completion designed for four (4) separate acid fracturing treatments in each well. The stimulation designs for both wells were prepared in such a way to have a similar fluid type, pumping sequence, and volume of reactive fluids. The major difference was the gaseous phase used to foam the fluid: CO2 was used in Well A and N2 was used in Well B. Post Fracturing flow- back parameters were measured and short pressure build-up analysis results compared between both wells.

Fracturing execution showed that CO2 can provide much higher foam quality than N2 (40% vs 12%) at the same total liquid pumping rates. Post-production showed that the well treated with CO2 gas was capable to produce at higher PI (Productivity Index) compared to the N2 well. Even after normalization to count the reservoir quality, well treated with CO2 showed better productivity compared to the N2 well.
An Integrated Approach to Deal with Challenges of Interpreting Pressure-Transient Data in Complex-Reservoir Systems
Authors: Phillips Guerrero Rodolfo J. , Al-Obathani Omar H.
Published: March 2019

A solid understanding of challenging reservoir complexities such as, naturally fractured "super-k" zones, layered systems, or, wellbore conditions such as, thermally induced mobility changes in the near wellbore region due to injection and uneven formation damage distribution across the wellbore, is essential for a successful development of carbonate reservoirs. These type of complexities play a major role for both reservoir fluid flow and well productivity. An efficient and holistic approach encompassing multiple data sources like image logs, production analysis logs, and pressure transient analysis (PTA) outcomes is of paramount importance in the characterization process of carbonate systems.

In this paper illustrative examples showing different complexities, at reservoir level and also at well level, are presented in a systematic way to show the importance of pressure transient analysis (PTA) insights as a building block in the description process of these challenging reservoir features. Reconciling the differences between the static and dynamic data sources in each case was a crucial step to minimize the uncertainties encountered and to significantly broaden the dynamic understanding of these complex reservoir heterogeneities under a synergistic approach. Pressure buildups and falloffs data from multi-well groups, were incorporated and analyzed by advanced numerical models. The selected interpretation models were dependent on the reservoir and wellbore condition diagnosed from the pressure derivative plots. The analyses of wireline and large, real-time Intelligent Field data have provided key dynamic well parameters, such as permeability-thickness product (kh), productivity index and anisotropy ratio (kv/kh), that were critical input parameters in the characterization process of these complex reservoir systems.
3D Reservoir-Scale Forward Geomechanical Modeling of Differential Compaction Fractures
Authors: Alzayer Yaser , Alnazghah Mahmoud , Zahm Chris
Published: March 2019

Differential compaction is an inherent process in carbonate systems that is thought to produce early natural fractures prior to any significant burial. Such fractures can persist and can be major permeability pathways, including areas of minor tectonic overprint. We forward model differential compaction fracturing in a carbonate reservoir in effort to predict the location of fractures in the subsurface.

3D finite-element geomechanical models are created to simulate differential compaction fracturing at a carbonate platform scale (kilometers) and the smaller carbonate build-up scale (10s of meters) commonly present within carbonate platforms. Interpreted seismic surfaces of key reservoir horizons are used as an input for the platform-scale model. Geometry of carbonate build-up from an outcrop analog is used for the build-up scale models. In both type of models layers identified to be compaction prone are restored to their expected pre-compaction state. A simplified mechanical stratigraphy scheme is adopted to distribute mechanical properties within the models consistent with their expected pre-burial properties.

Geomechanical modeling in this study was applied to a field which includes two carbonate platforms at different stratigraphic levels. Modeling results predict increased fracture intensity at the windward margin of the carbonate platform. This coincides with increased windward-leeward asymmetry of an underlying older platform. Increased fracture intensity is predicted at the center of the platform where the underlying older platform displays significantly less asymmetry. Predicted fracture locations over the platform top also correspond with the location of carbonate build-ups identified from seismic data. Fracture observations from image logs and indirectly from mud loss data within the upper platform are consistent with our modeling results. Predicted areas of greatest fracture intensity correspond with the location of wells with the highest fracture intensity observed from image logs.

Build-up scale models suggest that the build-up shape exerts a major control on the resulting differential compaction fracture pattern. Elongate build-ups tend to produce fractures oriented parallel to their axes. Circular build-ups tends to produce radial fracture patterns. Fracture orientation from image logs along with build-up shape observed using the coherence seismic attribute are consistent with these findings.

This study offers a process-based fracture modeling approach that can enhance the predictability of the location and orientations of natural fractures in carbonate reservoirs.
Underbalanced MPD of an Exploratory Well in Tight and Extra-Low Permeability Reservoir
Authors: Chen Peng , Zhou Yingcao , Wang Junjie , Chen Lei , Li Wanjun , Yang Guobin
Published: March 2019

Tight and extra-low permeability reservoir was usually explored by use of normal underbalanced drilling if the wellbore is stable and the formation pressure is clear. However, precise underbalanced MPD is the optimal technical solution in case the borehole is unstable and the formation pressure is unclear. Moreover, the precise underbalanced MPD would be effective for reservoir protection, enhancement of hydrocarbon discovery, improvement of ROP as well as reduction of well control risk.

No oil and gas show were found by previous conventional drilling in a tight granitic basement of Indonesia. The first exploratory well was planned to explore the broken belt of the basement to discover the oil and gas zone, increase drilling efficiency, prevent lost circulation at crushed zone of the basement and minimize drilling troubles by utilization of precise underbalanced MPD in the potential target zone. Underbalanced MPD was achieved by use of low density water-in-oil drilling fluid, and the bottomhole underbalanced pressure fluctuation was accurately and effectively controlled.

Underbalanced MPD operation was smoothly completed. Drilling with ignition under balanced managed pressure, connecting triples under balanced managed pressure, and tripping under balanced managed pressure were implemented. Slight under balanced condition of the bottomhole pressure during MPD operation was realized. The backpressure of the wellhead was accurately controlled between 55-135psi during precise MPD operation. 57 times of total accumulate successful ignition lasted 240 hours, which accounts for 80% of the total drilling time. The rate of penetration in tight target granitic formation under balanced drilling was improved and reached 10.8ft/hr. Neither losses nor overflow were detected during underbalanced MPD. Safe and high efficient drilling was realized. Good oil and gas show were observed. Abundant natural gas produced during underbalanced MPD. The basement hydrocarbon reservoir has been obtained important discovery.

Application of precise MPD technology could accomplish reservoir discovery and protection, wellbore stability and reduction of well control risk. It prevents ordinary underbalanced drilling from change over traditional overbalanced drilling due to unable to satisfy the safe drilling which would result in secondary damage to the reservoir so as to improve integrated drilling efficiency.