bluuebunny/crossref_metadata_2025 huggingface dataset:
Selectivizing a Singled Bed Reservoir, A Successfully Application to Increase the Vertical Displacement Efficiency in a Heavy Oil Waterflooding Project
Authors: Solórzano Pedro , Ahmedt Diana , Jaimes Claudia , Henao William , Vega Sandra , Guerrero Cindy , Meza Eliana , León Juan , Dueñas Danuil
Published: June 2018

This paper presents the application of multiple selectives injection zones within a high thickness singled bed heavy oil sand. The results were compared with a single zone completion in the same sand, establishing the differences in several aspects like recovery factor, vertical distribution efficiency, operation styles and completion difficulties.

This approach is based on the application of two methods of water vertical irrigation in a heavy oil sand, first, a singled 300’ zone completion and else, a 3-4 selectives zones completion, separating the equivalent injection in spaces of 60’-100’ thickness each. To route the flow, the packers were located next to thin shale planes most as possible. The objective was use this natural inundation surfaces intentionally as vertical permeability barriers looking forward to this works as a vertical flow controllers beyond wells selectivization, means like flooding separators, inside the heart of reservoir. In injector wells 3 types of behavior profile logs were ran several times within more than two years.

The reservoir under study it is the sand T2 located at Chichimene field, at the Colombia Llanos Basin. It has 320’/250’r of gross/net thickness, physically looks like a singled bed, it is saturated with high viscosity extra heavy oil of 350 cps, it is located at 9000’ measured depth (6000 - 6800’ TVDSS) the permeability shows a broad permeability range of 5 – 10000 mD. Waterflooding was initiated by 2014, the single zone completions wells, were exposed to a 6000 bls/d rate over very high permeability layer and this produced immediate channelization in thin layers only in some weeks after initiated. Producer wells increased water cut to high values, injection rates were controlled as results of its and finally some of the injectors had to be shut in. In the other set of wells, selective applications got separate the sand by 3 or 4 zones, the reservoir sand were irrigated by the same time, at the same rate of 6000 bls/d, almost 2000 bls/d each zone, this time the trends were simply different, means, producers water cut it was low and more stable. The results shows up about 2-3% of RF by simple zone completion in opposite to 6-10% of RF with selectives completions, evidencing a better vertical irrigation.

The case study presented in this paper, it is a successful curiously application of multiple selectives completions within a single sand. This example has been tested in field, it is an effective option in order to increase recovery factor and it will reborn expectations about the use of selectives completions over thick heavy oil sands. This results definitely; it will encourage engineers to think more about mechanical conformance applications in waterflooding.
Improvement of Microemulsion Generation and Stability Using New Generation Chemicals and Nano Materials During Waterflooding as a Cost-Efficient Heavy-Oil Recovery Method
Authors: Lee Jungin , Babadagli Tayfun
Published: June 2018

This study focuses on the ability of complex colloidal solution to stabilize a heavy oil-brine Pickering emulsion by changing the activity at the interface between heavy oil and brine. After testing many different combinations of anionic and cationic surfactants and nano-particles, we formulated the best stability options and created oil-in-water Pickering emulsions stabilized by silica, a cationic surfactant [dodecyltrimethylammonium bromide (DTAB)], and an anionic surfactant [alcohol propoxy sulfate (Alfoterra S23-7S-90)]. Then, various core flooding experiments were conducted in order to demonstrate the practical ability of the created emulsion system and observe its capacity to enhance oil recovery. Rate-dependency flooding tests were also conducted to determine the optimal flow rate required for heavy oil production through emulsification for different permeability media. Ultimately, slim tube sandpack flooding experiment at the optimal rate was conducted to confirm in-situ emulsion generation and to support the potential use of the chemical combination in the heavy oil industry.
Effect of Steam State on the Productivity of a Horizontal Well Pair During the Steam-Assisted-Gravity-Drainage Process: Physical Aspect Analysis
Authors: Zhao Lin , Jiang Hanqiao , Sun Fengrui , Li Junjian
Published: June 2018

Very limited studies were done on the superheated steam-assisted-gravity-drainage (SAGD) process. Besides, study of the effect of physical heating of steam at different state on the productivity during the SAGD process has not been reported.

In this paper, a numerical model is proposed to reveal the effect of physical heating on the productivity of a horizontal well pair during the SAGD process. Results show that: (a) the temperature increase of superheated steam plays a weak influence on the productivity of a horizontal well pair during the SAGD process. (b) the heated area increases with the steam quality, while the increase of the heated area under superheated steam injection is not obvious compared with the heated area when the steam quality is equal to 1.0. (c) as the mobility of oil in the steam chamber increases, the fraction of oil produced from the steam chamber increases, and the pressure near the production well increases. (d) when the steam quality increases or becomes superheated steam, the mobility of the oil in the steam chamber increases, and the supply rate of oil near the production well gradually become larger than the decrease rate of oil in the same region induced by elastic energy. This study provides a

The paper offers a comprehensive insight into the SAGD process, and helps petroleum engineers for SAGD project design in heavy oil reserves.
Applying Project Management Techniques to a Record-Breaking Ultra-Deepwater Frontier Drilling Operation
Authors: Nunes Carlos Eduardo , Smith Vance , Amer Ahmed , Tourinho Diogo Wink
Published: June 2018

This paper highlights the use of integrated project management techniques, as well as innovative drilling fluids technology, to safely achieve drilling objectives on a frontier exploratory, ultra-deepwater project offshore Uruguay. Drilling in a frontier offshore area adds layers of complexity due to inherent uncertainties and risks associated with these types of operations. The use of project management techniques, combined with application of novel drilling fluids technologies, served to mitigate and reduce project risks. Preparation for this well included regulatory review and HSE compliance procedures, facilities and logistics planning, the operator's understanding of the well complexities, selection of experts for each aspect of the operation, and contingency planning to include displacement and emergency disconnect. A thorough and comprehensive readiness review, coupled with communications processes, reinforced the project management loop. Critical path management and efficiencies of drilling operations dictated managing the logistics of mixing large volumes of drilling fluid at multiple locations. The well design program considered the possibility of encountering extreme sediment compaction arising from mass transport complexes (MTC) in the riserless interval. MTCs are a recognized geologic phenomenon and are typically avoided when drilling in deepwater areas of the world.1 The novelty of the workflow involved in safely and effectively delivering this record, frontier ultra-deepwater well included thorough planning and execution, in parallel with the use of new drilling fluid technology and facilities.
Integrated IOR/EOR Screening of an Offshore Oilfield in Trinidad
Authors: Garcia-James Celia
Published: June 2018

Objectives/Scope

An integrated benchmarking and screening study of IOR/EOR technologies used in analogous reservoirs worldwide was performed in the Southwest Soldado (SWS) Field offshore Trinidad, in order to establish the top three methods which could be implemented in this field to increase the recovery factor after more than 30 years producing under primary conditions.

Methods, Procedures, Process

The evaluation of IOR/EOR processes for the Southwest Soldado Field was done in 2 stages. Stage 1 included screening of processes to identify the top 3 methods to be used. Stage 2 involved the detailed evaluation of the top 3 processes. For Stage 1, the National Petroleum Council EOR Screening Method was used along with innovative techniques recommended by industry literature (Taber et al., 1997, Pérez-Pérez et al., 2001). In Stage 2, standard statistical methods were applied to the compiled database of successful IOR/EOR projects in offshore sandstone reservoirs. That information was used to establish a predicted recovery factor for the top 3 IOR/EOR methods selected. A theoretical description of the selected methods and their relationship with Southwest Soldado characteristics was done. Finally, considerations for pilot projects with recommended facilities, required logistics and cost estimates were analyzed and the best options were recommended.

Results, Observations, Conclusions

Given the characteristics of the Southwest Soldado field, Water Alternate Gas (WAG) injection resulted with the highest score based on the benchmarking exercise; Carbon dioxide (CO2) injection and water injection were selected in second and third place respectively. In the case of CO2, it was recommended as Huff and Puff in order to delineate transition zones, for ease of application in existing wells and facilities and for comparatively low cost. This method also generates high oil recoveries in a relative short period of time. Finally, it was recommended that for the implementation of a pilot project, Huff and Puff CO2 injection should be tested prior to WAG injection due to the many advantages in evaluating the reservoirs, quick execution and rapid production results at the lowest investment cost from the other 2 methods evaluated.

Novel/Additive Information

This paper presents the steps taken to benchmark an offshore field in Trinidad using the field's actual data. It lays the foundation for further development of heavy oil reserves in Southwest Soldado, highlights the challenges based on infrastructure, technology and economics requirements and provides a roadmap to further increase the recovery factor of these offshore heavy oil reservoirs.
Strengthening Capability for Oiled Wildlife Management in Trinidad and Tobago
Authors: Hosein Marianne Shalima
Published: June 2018

Despite Trinidad and Tobago having the highest biodiversity in the Caribbean and being an oil and gas producer for over 100 years, there is no approved systematic process to adequately address the protection, treatment and remediation of wildlife in the event of oil spills, apart from what is given in Section 5 of the 2013 National Oil Spill Contingency Plan (NOSCP).

BP Group requirements in 2012 stipulated the need for a documented process to manage oiled wildlife. Using international guidelines, a detailed review was conducted in 2013 to determine what was needed to establish an oiled wildlife preparedness and response programme in BP Trinidad and Tobago LLC (BPTT). This involved engagement of various external stakeholders (regulators, researchers, veterinary services, environmental non-governmental organizations [ENGOs], and international wildlife response organizations) to determine what had been put in place and what could have been established to manage national disasters involving wildlife.

Local animal rehabilitation centres were found to have limited capability to respond to large incidents. BPTT sponsored an Oiled Wildlife Preparedness Response Train the Trainer programme in 2013 to increase the number of volunteers available for oiled wildlife management by enabling the ENGOs to share the techniques with others. Formal volunteer training via ENGOs began in 2017. BPTT also established its own Level 1 Oiled Wildlife Response Kit comprising tools and equipment required to handle, treat and remediate wildlife impacted by oil. While developing its Oiled Wildlife Management Plan, BPTT was asked by the Ministry of Energy and Energy Industries (MEEI) to lead the initiative to further develop Section 5 of the NOSCP in collaboration with the stakeholders mentioned above and the other oil and gas operators. In 2016, the draft national Oiled Wildlife Management Plan was segment-tested during a BPTT major drill that involved a simulated uncontrolled offshore release of hydrocarbon which impacted emerging Green Turtle hatchlings on Manzanilla Beach. The learnings from this drill are being incorporated in the Trinidad and Tobago draft Oiled Wildlife Management Plan which will be added to the next update of the NOSCP.

BPTT remains committed to working with the stakeholders to obtain approval to formally implement this system. In the meanwhile, engagement with the different groups, ENGO training of additional volunteers, drills, data collection from actual incidents continues as capability in oiled wildlife management in Trinidad and Tobago is strengthened.
Risk Management of Major Oil Spill
Authors: Suárez Adriana , Ilizástigui Fidel
Published: June 2018

Major oil spills have the potential to become major environmental incidents. This paper aims to summarize the results of the study aimed at providing oil companies with more effective tools to help them better manage their environmental risks associated with the occurrence of major oil spills during offshore drilling operations. The latter is meant to be achieved by following a rigorous and systematic approach to the integrity management of environmental barriers and the performance of safety critical tasks in the same way the industry has long dealt with the management of integrity thereof.

The paper suggests complementing the approach contained in the IPIECA IOGP guidelines on oil spill contingency planning with DNV guidelines on environmental barrier management. This way the known cycle of ‘assurance and verification' will cover those barriers which are in place to mitigate the effects of major oil spills thus ensuring their availability and effectiveness when are called upon. This includes: a) the identification of environmental critical elements and tasks, b) development of performance standards c) identification of assurance and verification activities and d) the reporting of deviations to senior management levels and taking of corrective actions.

The paper introduces the Bowtie risk management methodology as a tool which supports the barrier management approach by linking technical risk analyses with safety management systems (SMS). This is thanks to its inherent strengths not present in other risk assessment methodologies such as event trees and fault trees. Last, but not least, the introduction of Bowtie methodology will facilitate understanding by all levels of the Oil Company of the role of the barriers in mitigating the effects of accident scenarios and their relationship with other barriers during the control of the accident scenario. The latter is realized through the motto that characterizes Bowtie methodology - ‘A picture paints a thousand words'.
Application of Time-Lapse Pressure Transient Analysis to Predict Gas Water Contact Movement and Water Breakthrough Time: Results from a Reservoir off the North Coast of Trinidad
Authors: Cassie Leon , Yaich Elyes , Singh Sidharth , Kaasa Anne , Jamankulov Arman
Published: June 2018

A single well, satellite gas accumulation offshore North Trinidad exhibits a strong water drive mechanism and is in pressure communication with two neighbouring fields through a common aquifer. Monitoring and predicting the movement of the gas water contact (GWC) is critical to reservoir management and resources estimation. This paper is the culmination of a study that was conducted over a five-year period, analyzing high quality downhole pressure buildup data to track the GWC movement in the field. Analysis of late time boundary dominated flow regime in multiple time lapsed pressure derivatives indicated a movement in the gas-water phase boundary, believed to be the contact. Pressure transient analysis (PTA) enabled the translation of shifting pressure derivatives to alternate GWC contour realizations. These matched derivatives provided a quantitative estimation of the contours which were then converted to an equivalent contact radius. For both edge water or bottom water drive mechanisms, the equivalent contact radius was then correlated to the field's cumulative gas produced. Prediction of water breakthrough was done by estimating a range of contours arriving near the well and calculating the corresponding recoverable gas volume from the generated correlation.

Multiple analytically derived functions were used to correlate the equivalent contact radius with the gas produced. A strong correlation was observed on regressing produced volumes with the interpreted contact radii. Due to inherent uncertainties with sweep efficiency, as a proxy, three idealized cases were defined for arrival of water close to the well to capture a low, mid and high scenario. Using these cases, water breakthrough was predicted to occur for produced volumes in the range of 58 Bscf to 70 Bscf, with a mid-case of 64 Bscf. In May 2015, actual water breakthrough occurred after 62 Bscf of production thus, strongly validating the robustness of the time lapse pressure derivative analysis study.

For gas reservoirs supported by moderate to strong aquifer drive, we suggest this as a robust workflow independent of 3D numerical reservoir simulation to predict recoverable volumes and water breakthrough timing. The observation of contact movement for gas reservoirs connected through a common aquifer could have significant implications on the conventional understanding around such reservoirs and their optimum management strategy.
Effect of Temperature, Phase Change, and Chemical Additive on Wettability Alteration During Steam Applications in Sands and Carbonates
Authors: Pratama Randy Agra , Babadagli Tayfun
Published: June 2018

One of the unanswered issues with steam applications is the wettability state during the process. Removal of polar groups from the rock surface with increasing temperature improves water wettability; however, other factors, including phase change, play a reverse role on it. In other words, hot water or steam will show different wettability characteristics, eventually affecting the recovery. On the other hand, wettability can be altered using steam additives. The mechanism of these phenomena is not yet clear. The objective of this work is to quantitatively evaluate the steam-induced wettability alteration in different rock systems and analyze the mechanism of wettability change caused by the change of the phase of water and chemical additives.

Heavy-oil from a field in Alberta (27,780 cP at 25°C) was used in contact angle measurements conducted on mica, calcite plates, and rock pieces obtained from a bitumen containing carbonate reservoir (Grosmont). All measurements were conducted at a temperature range up to 200°C using a high-temperature high-pressure IFT device. To obtain a comprehensive understanding of this process, different factors, including the phase of water, pressure, rock-type, and contact sequence were considered and studied separately.

Initially, the contact angles between oil and water were measured at different pressures to study the effect of pressure on wettability by maintaining water in the liquid phase. Secondly, the contact angle was measured in pure steam by keeping pressure lower than the saturation pressure. The influence of contacting sequence was investigated by reversing the sequence of generating steam and introducing oil during measurement. These measurements were repeated on different substrates. Different temperature resistant chemicals (surfactants and alkalis) were added to steam during contact angle to test their wettability alteration characteristics at different temperature and pressure conditions (steam or hot-water phases). The results showed that wettability of tested substrates is not sensitive to pressure as long as the phase has not been changed. The system, however, was observed to be more oil-wet in steam than in water at the same temperature, for example, in the case of calcite.

Analysis of the degree of the wettability alteration induced by steam (or hot-water) and temperature was helpful to further understand the interfacial properties of steam/bitumen/rock system and useful in the recovery performance estimation of steam injection process in carbonate and sand reservoirs.
Enhancing the Cement Quality Using Polypropylene Fibers
Authors: Ahmed Anas , Gajbhiye Rahul , Elkatatny Salaheldin , Kalimur Rahman Muhammad , Sarmah Pranjal , Yadav Prahlad
Published: June 2018

With the high global demand of oil and gas, oilfield companies are seeking resources in the unexplored areas by drilling wells to explore the potential reserves of oil and gas. The drilling process has become more challenging in these unexplored areas, especially at the high pressure and high temperature conditions (HPHT). A strong cement sheath is highly desired to ensure the durability and integrity of the wells to overcome these challenges. The cement slurry design and cementing job become more challenging especially when the process is carried out at the high pressure and high temperature conditions. Industry is always looking for the new material which can be stable at these extreme conditions and meet the requirement effectively and economically.

Polymer fibers are being used in the petroleum industry lately to assist in meeting these tough requirements. In this research, the usage of polypropylene fibers (PPF) on enhancing the oilwell cements properties at high pressure and high temperature (HPHT) were evaluated. The polypropylene fibers were added into cement admixture with discrete amount to evaluate its influence on enhancing the performance of cements especially those relate to the toughness.

Experiments were performed using distinct cement slurry characteristics such as rheological properties, thickening time, compressive strength, density, porosity and permeability. The Scanning Electron Microscope (SEM), and X-ray powder diffraction (XRD) was also performed for analyzing the microstructure of the cement.

The experimental tests showed that addition of fibers improves the mechanical properties, accelerates the thickening time, reduces the porosity and permeability and helps in designing a new cement slurry which withstands the HPHT conditions. Polypropylene fiber has a significant effect on reducing the porosity and the permeability of the base cement. Microstructural analysis showed that polypropylene fiber particles block the capillaries by filling the pores in the cement, so a dense cement structure is achieved.
Steam-Foam Assessment Using Native Cores from the Ratqa Lower Fars RQLF Heavy Oil Reservoir in Kuwait to De-Risk Field-Scale Deployment
Authors: Al-Murayri Mohammed Taha , Hassan Abrahim Abdelgadir , Kamal Dawood Sulaiman , Batôt Guillaume , Cuenca Amandine , Butron Jessica , Kantzas Apostolos , Suzanne Guillaume
Published: June 2018

Foam has been extensively investigated as a method to improve the mobility control of non-condensable gases in the EOR context. Recently, there has been renewed interest in foam applied to steam injections. However, steam is a condensable gas and thus steam-foam requires special analyses that differ from classical foam assessments. This work presents the coreflood results of a steam-foam process evaluation for the Ratqa Lower Fars (RQLF) heavy oil reservoir in Kuwait.

Using specifically designed foaming surfactants, coreflood tests in the absence and presence of heavy crude oil are performed in native sandpack cores under RQLF reservoir conditions (220°C; 360 psi). In order to limit steam condensation due to the build-up of the foam pressure, steam has been supplemented with a small amount of non-condensable gas (nitrogen, about 1 - 5 mol.%). Interstitial velocity was decreased from 40 ft/day down to 1 ft/day (CWE). Phase equilibria at the core inlet were estimated based on thermodynamics flash calculations. From these calculations inlet steam quality was varied from 10 to 70 wt.%. In absence of oil, the apparent viscosity of the generated steam-foam is measured between 25 and 50 cP, depending on the interstitial velocity and inlet steam quality. Indeed, beside the classical shear-thickening behaviour observed with the decreasing flow rates, the critical or optimal steam quality is found to be closed to 30 wt.%. Furthermore, even at higher steam quality the foam is still stable and efficient with a viscosity higher than 25 cP. Experiments in the presence of crude oil were carried out under the same conditions in native cores at a steam residual oil saturation of 7% and 13%. These experiments showed that the optimal steam quality is shifted to approximatively 10 wt.%. Furthermore, the foam flow curve shows a shear-thinning behavior that is elaborated upon. Finally, the viscosity in the presence of heavy crude oil of the generated steam-foam is within the range of 7 to 22 cP, depending on the oil saturation and on the injection conditions. Considering the oil viscosity (2 to 3 cP) under the same conditions, this means that the foam effect should translate into efficient improved conformance control of the steam within the reservoir.

For the first time, an efficient and stable steam-foam is generated in coreflood experiments. The generated foam achieved high apparent viscosities, even in the presence of oil, and this has not been reported in the literature to date. The results presented here are far more than a proof of concept as they bring new evidences regarding steam-foam efficiency and mechanisms with heavy crude oil.
Determination of Particle Shape and Size Distribution from Micro X-Ray CT Scans for Petrophysical Evaluation and Sand Control Design
Authors: Ghasemi K. , Mahmoudi M. , Roostaei M. , Fattahpour V. , Soroush M. , Nouri A.
Published: June 2018

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.
Integrity Failure of Cement Sheath Owing to Hydraulic Fracturing and Casing Off-Center in Horizontal Shale Gas Wells
Authors: Liu Kui , Gao Deli , Dahi Taleghani Arash
Published: June 2018

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.
Radial Permeability Measurement for Shale Using Variable Pressure Gradients
Authors: Fan Kunkun , Sun Renyuan , Elsworth Derek , Dong Mingzhe , Li Yajun , Yin Congbin , Li Yanchao
Published: June 2018

Shale gas is becoming an important addition to worldwide energy supply with permeability a critical controlling factor for gas production. Helium permeability determined using small pressure gradient (SPG)methods may lead to erroneous results when applied to actual field production with variable pressure gradients (VPG). In this paper, a VPG method using real gas (rather than He) is established to render permeability measurements more representative of reservoir conditions and hence response.

Dynamic methane production experiments are performed to measure permeability using the annular space in shale cores. Boundary pressure is maintained constant within each production stage with a designated pressure gradient and the gas production with time is measured. A mathematical model explicitly accommodating gas desorption uses pseudo-pressure and normalized time to accommodate the effects of variations in pressure-dependent viscosity and compressibility. General and approximate solutions to the model are obtained and discussed. These provide a convenient approach to estimate radial permeability in the core by nonlinear fitting to match the approximate solution with the recorded gas production data.

Results indicate that the radial permeability of the shale determined with methane is of the order of of 10-6∼10-5md and decreases with an increase in average pore pressure. This is contrary to the observed change in permeability estimated with helium. Permeability errors obtained from the SPG method using helium are several times greater than those obtained from the VPG method using methane. Bedding geometry has a significant influence on shale permeability. The superiority of the VPG method is confirmed by comparing permeability test results obtained from both VPG and SPG methods.

The VPG method has two advantages: The first is that reservoir gas can be used in the VPG method instead of helium, better incorporating potential desorption impacts in permeability evltuion. The second is that realistic pressure dependent impacts can be accurately accommodated, making this method more applicable to gas production conditions in the reservoir. Although several assumptions are used, the results obtained from the VPG method are much closer to reality and may be directly used for actual gas production evaluation and prediction.
Numerical Modeling of Water-Soluble Sodium Silicate Gel System for Fluid Diversion and Flow-Zone Isolation in Highly Heterogeneous Reservoirs
Authors: Khamees Tariq K. , Flori Ralph E. , Fakher Sherif M.
Published: June 2018

This study presents a numerical modeling of a sodium silicate gel system (inorganic gel) to mitigate the problem of excess water production, which is promoted by high heterogeneity and/or an adverse mobility ratio. A numerical model of six layers was represented by one quarter of five spot pattern with two thief zones. CMG-STARS simulator was used that has the capabilities of modeling different parameters. The gelation process of this gel system was initiated by lowering the gelant's pH, and then the reaction process proceeded, which is dependent on temperature, concentration of the reactant, and other factors. An order of reaction of each component was determined and the stoichiometric coefficients of the reactants and product were specified. The purpose of this study is to develop a thorough understanding of the effects of different important parameters on the polymerization of a sodium silicate gel system.

This study was started by selecting the optimum gridblock number that represents the model. A sensitivity analysis showed that the fewer the number of gridblocks, the better the performance of the gel system. This model was then selected as a basis for other comparisons. Different scenarios were run and compared. The results showed that the gel system performed better in the injection well compared to the production well. In addition, the treatment was more efficient when performed simultaneously in injection and production wells. Placement technology was among the parameters that affected the success of the treatment; therefore, zonal isolation and dual injection were better than bullhead injection. Lower activator concentration is more preferable for deep placement. Pre-flushing the reservoir to condition the targeted zones for sodium silicate injection was necessary to achieve a higher recovery factor. Moreover, different parameters such as adsorption, mixing sodium silicate with different polymer solutions, effects of temperature and activation energy, effects of shut-in period after the treatment, and effects of reservoir wettability were investigated. The obtained results were valuable, which lead to apply a sodium silicate gel successfully in a heterogeneous reservoir.
Bubble Population Balance Modeling to Predict Propagation Distance of CO2 Foams in Enhanced Oil Recovery Processes
Authors: Izadi Mohammad , Kam Seung
Published: June 2018

A mechanistic foam modeling technique based on bubble population balance, which honors three different foam states (weak-foam, strong-foam, and intermediate states) and two steady-state strong-foam flow regimes (high-quality regime and low-quality regime of the strong-foam state), is developed to investigate how CO2 foam behaves rheologically and propagates in a petroleum reservoir. The model parameters are first obtained from a fit to existing laboratory coreflood experimental data, and then the mechanistic model is applied to different types of CO2 foams, ranging from gaseous to supercritical CO2 foams, represented by various mobilization pressure gradients.

The results from the fit to existing coreflood data show that a reasonable match can be made satisfying multiple constraints such as hysteresis exerted by three foam states, non-Newtonian flow behavior caused by gas trapping and shear thinning rheology, and bubble stability at different capillary pressure environments. Among different sets of input parameters resulting in equally nice fits, an additional experimental data (for example, the onset of foam generation by increasing the total flow rate step by step at fixed foam quality) can help narrow down the range of input parameters further. When applied to field-scale scenarios, supercritical CO2 foams requiring low mobilization pressure gradient propagate much further than gaseous CO2 foams, far enough to make use of supercritical CO2 foams promising in the fields. This in turn proves theoretically why supercritical CO2 foams should be preferred in the field compared to gaseous CO2 foams. The model shows foams in the low-quality regime can propagate longer distance than foams in the high-quality regime because of better foam stability at lower capillary pressure environment.
A New Kind of EOR for Trinidad
Authors: Delamaide Eric
Published: June 2018

Enhanced Oil Recovery (EOR) has been utilized in Trinidad and Tobago for over 50 years. Most projects so far have focused on thermal as well as gas injection along with the more conventional waterfloods. In spite of that, recovery factors are still relatively low and the country's oil production has been declining for some time. Surprisingly, given the progress in chemical EOR and in particular polymer flooding in the last 10 years, these processes have not been used in Trinidad and we suggest that it might be time to consider their application. Similarly, foam has been used extensively worldwide to improve performances of gas and steam injection but has not yet been used in the country.

The situation of EOR in Trinidad will be first reviewed along with the characteristics of the main reservoirs. Then the potential for the application of chemical-based EOR methods such as polymer, surfactant and foams will be studied by comparing the characteristics of Trinidad's reservoirs to others worldwide which have seen the applications of chemical-based EOR methods.

This review and screening suggests that there is no technical barrier to the application of all these EOR methods in Trinidad. Most reservoirs produce heavy oil and are heavily faulted, but polymer injection has been widely applied in heavy oil reservoirs as well as in faulted reservoirs before, and suitable examples will be provided in the paper. Similarly, these characteristics do not present any specific difficulty for foam-enhanced gas or steam injection. The main issue appears to be the identification of suitable water sources for the projects.

This paper proposes a new look at EOR opportunities in Trinidad using conventional methods which have not been used in the country. This will help reservoir engineers who are considering such applications in the country and hopefully will eventually result in an increase in the oil production in the future.
Exploiting Water Injection Techniques for Increasing Gas Recovery in Conventional Gas Reservoirs
Authors: Rambaran Keval Darvesh , Chin Chee Fat Sarah Tammie , Layne Lugard Evans
Published: June 2018

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.
Bond Log Analysis Offshore Trinidad
Authors: Welsh Christian Paul
Published: June 2018

This paper analyses the results of the combined Cement Bond Log/ Variable Density Log /Radial Bond Log (CBL/VDL/RBL) tool run on 10 consecutively drilled offshore development wells by an operator during the 2015/2016 period in Trinidad and Tobago. The Bond Index (BI) is used as a quantitative criterion for measuring cement to casing bond and the VDL/RBL as a qualitative criterion for cement to formation bond. The performance of the wells after perforation is examined with the aim of highlighting the importance of a good cement job for successful production. Cement pump pressure/pump rate/cement density charts are also examined to explain cement job outcomes.
Performance of CO2/N2 Foam in Enhanced Oil Recovery
Authors: Hassan Mohamed , Gajbhiye Rahul
Published: June 2018

Carbon dioxide (CO2) flooding is one of the attractive enhanced oil recovery process. Although it has several advantages, it suffers from early gas breakthrough due to low mobility ratio. The early breakthrough and mobility ratio can be improved by foaming CO2 gas. But CO2 is unable to generate the foam especially at supercritical condition (1100 psi at 31.10C) which is generally found in the reservoir. The CO2 foam gets weaker and weaker with an increase in pressure. It reduces the macroscopic sweep efficiency and hence the ultimate recovery.

The difficulty of generating CO2 foam is overcome by adding N2 in a small fraction to enhance the foam generation of CO2 at supercritical conditions. This study shows how the addition of small quantity of N2 helps in generating the CO2 foam and performance of the novel CO2/N2 mixture foam in enhanced oil recovery.

The goal of this study is to evaluate the oil displacement process by a novel foam system in which the CO2 and N2 mixture constitutes the gaseous phase. The experiments were carried out by flooding the core with CO2/N2 foam by imposing the condition above the supercritical CO2. The supercritical CO2 becomes denser and unable to generate the foam. To generate foam nitrogen is added to carbon dioxide to improve the CO2 ability for generating CO2 foam at supercritical conditions.

The CO2/N2 foam performance is evaluated by comparing displacement efficiency of CO2 foam with CO2/N2 foam. In addition, the effect of foam quality by fixing the injection rate were investigated on CO2/N2 foam flooding performance.
Application of Blasingame Type Curves to a Multi-Well Gas-Condensate Reservoir: Field Case Study
Authors: Adrian Pedro Marcelo , Cabrera Marcia Ruth
Published: June 2018

Nowadays advanced decline curve analysis techniques are widely accepted for estimating Hydrocarbon Initially in place (HCIIP), reservoir parameters and production forecasting. These analytical techniques were developed assuming different reservoir models and wellbore geometries. Most of them considered an ideal single well reservoir system, which is not a common scenario of production.

In light of that, some authors have proposed theoretical solutions for the analysis of production data of multi-well reservoir. Gas and oil reservoirs has been studied and validated with reservoir simulation models; however the application to real field case was not addresses in detail. There is an example for gas-condensate reservoir with the multi-well approach and the other for an oil field by applying a single well methodology.

This paper presents a field case study application of Blasingame type curve method to a multi-well gas-condensate reservoir. Total material balance pseudo-time was calculated using the two-phase compressibility factor. Bottomhole flowing pressures were calculated with vertical flow correlations and adjusted with dynamic gradients. A single well production data was analyzed to estimate the total Original Gas In-Place of a gas-condensate reservoir as well as reservoir parameters.

The results of the multi-well method were comparable with volumetric and conventional material balance estimations, as well as well testing interpretation results. Therefore the reliability of the multi-well type curve approach to gas-condensate reservoirs was confirmed.
Engineered Wellbore Strengthening Application Enables Successful Drilling of Challenging Wells
Authors: Chimara Godwin , Calder Alan , Amer Wael , Leslie Philip
Published: June 2018

Four wells were successfully drilled and completed, but high drilling fluid densities (1.95 to 1.98 SG) were necessary to maintain wellbore stability in the overburden section immediately above the depleted reservoir. The estimated hydrostatic overbalance from the drilling fluid was approximately 800 bar (11,603 psi) higher than reservoir pressure. A wellbore strengthening technique was selected to seal the calculated 1500 μm fractures induced by these high pressures. This paper highlights the engineering, logistical, and operational challenges encountered while successfully drilling and completing such wells.

Geomechanical data was initially acquired, including Young's modulus, Poisson's ratio, and minimum in-situ horizontal stress; and, together with the operational parameters [hole diameter and equivalent circulating density (ECD)], these data were used to estimate fracture width (1500 μm). Subsequently, a drilling fluid system was engineered and customized to seal such fractures, thereby strengthening the wellbore to help minimize losses in the reservoir. The solution was validated at two separate laboratories. Large particulate materials with a D50 of 600 to 2300 μm were used. Improvement opportunities during execution were captured for the next cycle.

A total drilling fluid loss of 512 m3 during a 16-hour period was experienced in one well after a drilling liner packoff occurred, and fractures greater than 1500 μm were initiated; however, the liner was successfully cemented in place. The coarse particulate materials (600 to 2300 μm) were mobilized in 500 and 1000 kg bags to minimize deck space requirements on the rig and help facilitate ease of mixing. Rig mixing and pit agitation capacity were important for effective mixing of the fluid system. The application also provided the opportunity to align testing procedures and equipment between the field and laboratory. With increasing reservoir depletion, the potential exists for fracture width increases that can impact the particle size of materials necessary to effectively design a solution. Engineered particulate solutions provided a pathway for sourcing and procuring the necessary wellbore strengthening materials.