Mohamdally, Muzaffar (University of Trinidad and Tobago) | Soroush, Mohammad (University of Trinidad and Tobago) | Zeidouni, Mehdi (Louisiana State University) | Alexander, David (University of Trinidad and Tobago) | Boodlal, Donnie (University of Trinidad and Tobago)
Fault transmissibility and leakage have significant implications for field development during both primary and post-primary recovery. Whether the fault is sealing or not can directly determine the sweep efficiency and the fate of injected fluids. In addition, fault transmissivity affect the accuracy of in-place volume calculations from material balance techniques. In this paper dynamic data was used to determine transmissibility and leakage of the faults via Capacitance Model (CM).
The CM has been developed from linear productivity model and material balance equation. Its inputs are production/injection rates and bottomhole pressure data (if available). The CM has weight factor for each well pair which determines the degree of connectivity between that pair. These weight factors were used and correlated to the fault transmissibility in this paper. Also, the CM was modified to incorporate the leakage in the system. New term, called leakage factor, was added for each well in the equation.
The model was examined through applying to several synthetic field data generated by CMG software. In synthetic fields, different faults with different throw and transmissibility were built and across the fault transmissibility was evaluated by the model. For creating leaking fault, upward leakage and flow along the fault were examined. Estimated zero leakage factor means no leakage and one means maximum leakage for the wells. The leakage factors not only identified where the leakage was happening, but also determined the amount of leakage by multiplying leakage factor to the net accumulation.
In reservoirs with complex geology and several faults, commonly encountered in Trinidad, all geological and geophysical complexities might not be accurately known. Using alternative methods such as the CM can complement, validate or better determine fault properties such as leakage and transmissibility for proper application of EOR schemes.
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.
Almeida, Alana (Universidade Federal da Bahia, University of Alberta) | Patel, Rajan (University of Alberta) | Arambula, Carolina (University of Alberta) | Trivedi, Japan (University of Alberta) | Soares, João (University of Alberta) | Costa, Gloria (Universidade Federal da Bahia) | Embiruçu, Marcelo (Universidade Federal da Bahia)
Several researchers have demonstrated in laboratory experiments and field applications that reducing the concentration of salts and the content of multivalent cations in the injection water may increase oil recovery. This study evaluates the performance of low salinity water injection (LSWI) in oil recovery using a crude oil and synthetic formation water of a sandstone reservoir in northeast Brazil. Two Botucatu sandstone core samples of 6 in of length and 2 in of diameter were used for the coreflooding experiments. The fluids used included a light crude oil sample, and synthetic formation water (SFW) produced from the four main salts of the original formation water (NaCl, KCl, CaCl2, and MgCl2). In Core 1, two injections were carried out at an average reservoir temperature of 60 °C, one using SFW with 200,000 mg/l as secondary recovery mode, and one using SFW diluted 40 times (40xd_SFW) resulting in a low salinity water of 5,000 mg/l as tertiary recovery mode. In Core 2, 40xd_SFW was injected at the same temperature to compare the high and low salinity water effects in the secondary mode. Moreover, zeta (ζ) potential measurements on Botucatu sandstone powder were performed in 6 dilutions of the SFW and deionized water. The experimental results demonstrated an increase in oil recovery and pH when 40xd_SFW was injected in secondary and tertiary modes. The effluent ionic concentration from Core 1 showed the reduction of Ca2+ during HSWI, indicating its adsorption on the rock surface. Most remarkably, Ca2+ concentration increases and the Na+ concentration decreases in the effluent samples in the first LSWI pore volume injected, which suggested ionic exchange of calcium for sodium on the rock surface. Furthermore, Fe2+/Fe3+ and traces of Al3+ were observed in the effluent demonstrating the occurrence of fine migration in SFW and 40xd_SFW. The magnitude of negative ζ potential on Botucatu sandstone increases as the salinity of the brine solutions decreases. Based on that experimental study, it is noticed that a set of LSWI mechanisms occurr simultaneously in Botucatu sandstone, and oil and brine samples from Recôncavo Basin, indicating a potential of application for LSWI in similar Brazilian oil reservoirs.
The objective of this study was to systematically and quantitatively quantify where production from Thin – Bedded Pay may be more challenging using conventional methods of completion. This study will focus on different areas within the deltaic environment in which Thin – Bedded Pay are prominent. A 3D structural model was built and populated with properties to represent four (4) different main classes of geological environments with a deltaic system. It explored the effect of completing across the conventional sands only vs completing both the conventional and secondary units. The main finding in this thesis is that completing the thin-bedded pay increased the overall rate of the production on average of about 10% in different environments. In addition, in complicated reservoir architecture environments such as the upper slope and distal delta slope environments, there are significant (14% and 10%) incremental increases in the recovery factors by completing across these thinly bedded zones. Thus, it is recommended that these environments be further explored in how best to develop the thin-bedded resource in these environments since, in a time when the finite resources of oil and gas are becoming scarce, it is important to understand what reserves we may have that are not currently being tapped into.
Fakher, Sherif (Missouri University of Science and Technology) | Abdelaal, Hesham (Silesian University of Technology) | Elgahawy, Youssef (University of Calgary) | El Tonbary, Ahmed (American University In Cairo) | Imqam, Abdulmohsin (Missouri University of Science and Technology)
When producing from gas hydrate reservoirs using steam flooding, since hydrate dissociation is an endothermic reaction, the heat is used up. This results in a decrease in reservoir temperature which causes the hydrate equilibrium conditions to be established again, thus causing hydrate reformation. This research studies the effect of injecting thermodynamic inhibitors during steam injection on overcoming the problem of hydrate reformation which in turn will increase hydrocarbon recovery significantly from hydrate reservoirs. The reservoir model was built based on data collected from previous models found in the literature. After specifying all parameters for the reservoir, and the hydrate layer, a systematic study was performed in order to assess the use of inhibitors with steam flooding. The production methods studied include depressurization, steam flooding, inhibitor injection including both brine and glycol, and finally the combined steam flooding inhibitor injection method. The conditions for the steam flooding were kept the same during all runs in order to be able to compare them. Results indicated that the use of the thermal stimulation alone without inhibitor managed to increase recovery, however, the problem of hydrate reformation occurred which caused a cessation of production. Using inhibitors alone managed to increase recovery as well, however the recovery increase was much less compared to thermal stimulation. The type of inhibitor also played a role in recovery with the glycol producing the most, followed by the brine. By combining both steam flooding and inhibitor injection, the recovery increased significantly more than what was observed when using each of the methods on its own. To the authors' knowledge, no extensive study has been performed by combining both steam flooding and inhibitor to increase hydrocarbon recovery from hydrate reservoirs. This research can help in improving real field gas hydrate projects by making the overall project much more economic by increasing hydrocarbon recovery.
Sand associated to oil production in Jusepin field located in east Venezuela, has generated damages in oil and gas surface facilities, resulting in unscheduled production stops caused by surface equipment breakdowns, which increases maintenance costs and impacts negatively on the company's productivity. Researches determined that well J-502 was causing these operational problems, in response it was decided to install a sand trap at the well head in order to evaluate its effectiveness. The device has a simple design without moving parts and counts with a separate solid storage area, which allows disposing the retained sand without affecting the production of the oil well. Its principle of capture is the speed reduction due to fluids expansion, based on Stokes’ Law. In addition, its inlet is connected to the well head and the outlet to flow line. The data used for the design of the equipment were: Oil API Gravity 31.5°, Oil Rate: 1969 Barrels per Day, BS&W 20.4%, Gas Rate 14.9 MMSCFD, Operating Pressure 1350 psig, the size of sand grains, which varies between 90 and 600 microns and its density (1,304 gr/cc). This information was used to calculate the dimensions of the equipment (Diameter and Length) necessary to decant the sand particles inside of it.
After installing the sand trap, the number of stoppage in the flow station dropped from 18 per year to none, preventing deferred production of more than 7,600 barrels of crude per year, with savings in maintenance costs up to 30,000 US$ per year. Likewise, after 84 days operating, it was able to retain as much as 4 cubic meters of sand (141 cubic feet). In conclusion, the success achieved demonstrated the effectiveness of this useful device and its profitability was proved through an economical evaluation. Finally, the sand trap represents an innovative and effective solution in cases where the sand cannot be retained from the bottom hole. For this reason, it would be recommended to implement this solution in wells with sand production problems, and in a greater extend, in downstream facilities such as flow stations, in order to enhance effectiveness by using a higher capability device interconnected to various wells instead of one sand trap for each well, this will reduce manufacturing and installation costs.
Integrated asset modeling has been used for the last decade with a wide technical application covering different challenges from field development to production optimization. Besides supporting the FEEDS and FEL studies for different purposes. Moreover, the technology has evolved in terms of integration and dynamic or transient simulation has been added as an extra element expanding the possibility to cover different challenges and workflows. The objective of this paper is to show how this dynamic integration (Dynamic integrated asset modeling) was applied to a common problem of several reservoirs that produce water and gas under different dynamic mechanisms (injection, aquifer and gas cap) to understand, from the reservoir perspective, the effects of gas and water conning over the entire production system.
The methodology applied was using a refined sector model solved with numerical simulation and coupled with a transient multiphase flow simulator to see how pressure drop affect the contacts level and shape based on the petrophysical properties and under different production scenarios and generate different graphics to see how this phenomenon behaves. Besides a comparison with all the most analytical correlations used in the literature to identify gas and water conning was performed to see the differences among them and with this dynamic integrated approach. On the other hand, for the production side this coupled model was applied to an offshore facility to see these reservoir effects in the transport system and how they impact in the pipeline and riser due to this abrupt entrance of gas and water changing the flow conditions, flow patterns, pressure drop and creating some instabilities in the separators caused by severe slugging.
The results of this analysis were very useful to understand the total production systems (reservoir-surface) behavior, predict the gas and water breakthrough, establish the critical rates to avoid these problems and see how the results differ in some cases with the common analytical correlations. Specific conditions in the pipeline and riser were established to quantify the slugging problems and evaluate different alternatives to eliminate the instabilities through proposing different scenarios such as gas injection in the riser, top side choking, etc. Application of this integrated approach has been very beneficial in recognizing the source of the problem, offer proper and feasible solutions in development and operational phases. In addition, validating and reducing uncertainty of related literature correlations and give to the production and reservoir engineers a quick and reliable way to know the critical rates that can support the decision-making process.
Razack, Javed (Ramps Logistics Ltd.) | Nazir-Khaleel, Imtiaz (Ramps Logistics Ltd.) | Rampersad, Shaun (Ramps Logistics Ltd.) | Zambrano, Alvaro (Ramps Logistics Ltd.) | Chandarjeet, Shivani (Ramps Logistics Ltd.) | Choon, Sachin (Ramps Logistics Ltd.)
Since 2015, over a dozen deepwater exploration and appraisal wells have been drilled across Trinidad, Guyana and Suriname. By 2020, these three countries are expected to see at least another twenty-five deepwater wells being drilled. These include 17 development wells for Guyana's massive Liza field. Seismic exploration is also being conducted over unexplored deepwater blocks in Guyana and Suriname, which could pave the way for even more wells during this period.
A key element in the offshore drilling supply chain is the onshore supply base. This shorebase is the logistics hub for all drilling activity. Supply vessels commute between the rig and shorebase, where they are loaded with all drilling fluid, cement, drillpipe, logging tools, food supplies, and any other equipment needed by the rig. Fuel and potable water for the rig are also loaded at the shorebase. When the vessels return from the rig, they unload waste generated at the rig and demobilize tools, unused drillpipe and so on.
The shorebase must have the following: covered warehousing, flattened and reinforced laydown yard, offices for support staff, and quayside access with a dock that is long enough and with deep enough draft to accommodate the supply vessels when fully laden with cargo. The shorebase must also have sufficient crews for loading and unloading of materials, as well as heavy equipment such as cranes and forklifts. Vessels must also be able to access electric power and load potable water, drill water and fuel.
In Guyana and Suriname, natural deepwater ports do not exist due to sedimentation from several rivers like the Berbice, Essequibo, Demerara and Paramaribo. The severe draft restriction means that the large supply vessels required to take cargo to the rig cannot easily dock in Guyana or Suriname. Moreover, Trinidad has many major multinational service companies already set up, so the majority of equipment and materials needed for drilling must emanate from Trinidad. Further, since Trinidad has a mature oil and gas industry, there are several shorebases already set up to service drilling operations. As a consequence of these three main factors, the primary shorebase for all wells in Guyana and Suriname have been located in Trinidad.
With the Liza field being developed, ports are being renovated in Guyana while more service companies are aiming to set up there. However, until a deepwater shorebase is built in either Guyana or Suriname, the primary supply base for these wells must come from Trinidad. Secondary supply bases have been located in Guyana or Suriname, to facilitate smaller supply vessels and emergency support.
Ramnath, Jonathan (University of Trinidad and Tobago) | Felix, Elroi (University of Trinidad and Tobago) | Shah, Ahmid (University of Trinidad and Tobago) | Soroush, Mohammad (University of Trinidad and Tobago) | Omokughegbe, Nykesi (University of Trinidad and Tobago) | Jaipaulsingh, Francis (University of Trinidad and Tobago)
Decreasing oil production and increasing quantities of greenhouse gases continue to be an issue plaguing Trinidad and Tobago's energy sector. While CO2 EOR has been proven to be an effective solution to both of these problems it is often overlooked in Trinidad due to the inability of the gas to achieve miscibility with the crude oil as well as operational limitations such as an absence of transportation pipelines for the CO2.
Even though miscibility may not be achieved, immiscible CO2 EOR can effectively increase production and sequester CO2 resulting in an increase of revenue as well as decreasing the quantity of greenhouse gases vented to the atmosphere. This paper aims to highlight the possibility of implementing immiscible CO2 projects in Trinidad. The scientific processes that are responsible for increased crude oil production are discussed and the operational considerations for a safe and economically feasible project in Trinidad South West fields are examined.
It was seen that the vaporizing gas drive process would not result in miscibility in the shallow low pressure fields of the South West Trinidad however it would cause a significant reduction in the interfacial tension, this in turn causes an increase in the capillary number which would result in additional oil recovery. It was also found that the high viscosity of the non-carbonated oil of the region would result in an even greater reduction in viscosity when it is mixed with the CO2 gas resulting in more favourable oil mobility. The high solubility of CO2 in hydrocarbon liquids result in the swelling of crude oil. In the water wet formations, the oil within the pore spaces swells, resulting in an increase of relative permeability aiding in additional oil recovery.
In the field evaluated, it is proposed that the CO2 be acquired from Atlantic LNG, tube trailers be used to transport the CO2, 100mmscf of gas injected per day with a 5spot injection pattern and the produced gas compressed and reinjected. From simulation this was found to produce an additional 389,360bbls of oil where CO2 would be sequestered and an additional profit of US$ 21,414,800 would be acquired within a 20 year period.
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.