Determining the most influential parameters affecting the reservoir flow responses is a vital step in the integrated reservoir studies for evaluation and analyses. More specifically, removing the non-influencing parameters leads to reach the optimal process design. The conventional procedure to determine the most sensitive parameters combines regression analysis with analysis of variance. However, that approach produces one reduced regression model after eliminating the non-influential parameters (deterministic approach). In this paper, Bayesian Model Averaging (BMA) was applied to stochastically identify the geological parameters that control the immiscible CO2-assisted gravity drainage process performance in a multilayer heterogeneous sandstone oil reservoir in South Rumaila oil field. After achieving acceptable history matching within approximately 57 year of production, the CO2-assisted gravity drainage injection was evaluated in 10 year future prediction. In that process, vertical wells were placed at the top of the reservoir for CO2 injection to formulate a gas cap that make oil drains down towards the bottom of reservoir. Above the oil-water contact, a series of horizontal production wells were installed to produce oil. The main geological parameters that controls the immiscible CO2 flooding are horizontal permeability, anisotropy ratio (Kv
A pressure transient model to detect fault reactivation is presented in this paper. The central assumption of the fluid flow model is that fault permeability gets suddenly altered upon fault slip. The fault is modeled as a linear interface segmenting an infinite, homogeneous and isotropic reservoir into two semi-infinite regions. A constant-rate well induces pressure changes in the reservoir by either fluid withdrawal or injection that lead to fault reactivation. The mathematical model is solved via integral transforms and the analytical solution is examined at the well with the purpose to find the characteristic bottomhole pressure and pressure derivative response to a fault slip event. Typical diagnostic plots and type curves used in well testing analysis are presented. A reservoir characterization approach summarizes the application of the model presented in this paper.
The latest pulsed neutron spectroscopy tool for logging behind casing provides for enhanced formation evaluation due to improved self-compensated sigma and porosity measurements and a new measurement, the fast neutron cross section (FNXS), which is independent of the formation hydrogen index (HI). The FNXS is highly sensitive to gas filled porosity and can be used to differentiate between gas-filled and low-porosity zones, which was previously not possible. The FNXS measures the ability of the formation to interact with fast neutrons which is highly dependent on atomic density and not dominated by any particular isotopes, in contrast to traditional sigma and porosity measurements.
This paper examines and compares the results of gas identification and lithology identification using pulsed neutron spectroscopy in an open-hole and a cased-hole environment. Most pulsed neutron tools are run after casing; this study provides a unique example to compare the effect of casing on the spectroscopy by comparing the cased hole measurements to measurements taken in the open hole, before the casing was run.
There are several parameters affecting the net and gross CO2 utilizations during a CO2-EOR process. Although many of the parameters cannot be changed for a specific hydrocarbon reservoir, the field development strategy is one of the parameters that could be chosen in a way to get the most favorable CO2 utilization ratios, oil production, and CO2 storage. This paper presents a field scale compositional reservoir fluid flow model in the SACROC (Scurry Area Canyon Reef Operators Committee) unit, Permian Basin. The model was developed to investigate the impact of various injection scenarios, such as CGI (Continuous Gas Injection) and WAG (Water Alternating Gas) on CO2 utilization ratio, oil production, and CO2 storage during CO2 injection. Additionally, we demonstrated the amount of stored CO2 in different phases: dissolved in brine, miscible in oil, residual CO2, and mobile CO2 and correlated the contribution of different trapping mechanisms to the utilization ratios. A high-resolution geocellular model, which was constructed based on wire-line logs, seismic surveys, core data, and stratigraphic interpretation, is used for numerical simulations. Previous studies skipped the history matching of the field; however, the initial distribution of fluids plays an important role in CO2–EOR efficiency. Therefore, a comprehensive history matching of primary, secondary, and tertiary recovery was conducted for this study. The history matching process included matching the average reservoir pressure, the oil and water production, and most importantly the gas production. The results show that the utilization ratio is not a constant number and evolves during the injection period. The results of this study also shows how the evolution of oil miscibility trapping over the injection time controls the evolution of net CO2 utilization ratios. CGI showed higher utilization ratios than WAG. We also compared both the total stored amount and the amount of stored CO2 in different phases. Finally, we compared the amount of produced oil for the assumed field development strategies. Results show that the amount of produced oil by WAG and CGI are so close. Among the various scenarios explored, WAG seems be a promising operational approach to balance both storage and oil production. The present work provides valuable insights for optimizing oil production and CO2 storage based on the evolution of net CO2 utilization ratios.
New underground injection control (UIC) regulatory activity come with challenges. California regulatory agencies have enhanced scrutiny on underground injection projects. One of the requirements under the California UIC regulations is to collect formation water samples and submit water analysis results together with the application package to confirm whether the Total Dissolved Solids (TDS) of a formation or aquifer is greater than 10,000 ppm, which is non-underground source of drinking water (non-USDW) under the federal Safe Drinking Water Act (SDWA).
Various methodologies for collecting water samples were evaluated before selecting wireline tools, to collect water samples. The water samples were collected open-hole using downhole special wireline equipment with high technologies to analyze/detect not only fluid types being pumped through tool's flowline but also the contamination levels (due to mud filtrate invasion), to prove the representative formation fluid quality of the collected samples.
This paper summarizes water sampling methods using two different types of wirelines sampling tools from two different leading wireline contractors. Depending on the key sensors each tool has, strategies to detect contamination levels were studied and developed. The following executions and on-the-fly decision making have proved this sampling method is the most suitable and cost-effective for the specific regulatory required sampling.
Formation water samples were successfully collected with monitored contamination levels to prove the accuracy of the formation TDS of this sampling method compared to the log-derived TDS. This crucial data helps demonstrate the TDS and water quality in order to comply with California UIC requirements.
This is a new sampling method that had never been used in the San Joaquin Valley region for formation water sampling. Despite initial concerns from regulatory agencies about the accuracy of this method, the regulators have not only accepted this formation water sampling technology, but now advocate for its use by other operators.
Hamza, Farrukh (Halliburton) | Sheibani, Farrokh (Massachusetts Institute of Technology) | Hadibeik, Hamid (Halliburton) | Azari, Mehdi (Halliburton) | Esawi, Mohamed (Halliburton) | Ramakrishna, Sandeep (Halliburton)
Hydraulic fracturing is now considered to be a standard completions process used to improve oil and gas recovery in unconventional reservoirs. Injection/fall-off pressure from a micro-fracturing test contains important geomechanical information, including the inference of the minimum horizontal stress, natural fracture permeability, and in-situ pore pressure. The determination of in-situ stress is crucial for designing, modeling, and evaluating hydraulic fractures. This paper presents a field example of a micro-fracturing job to determine minimum horizontal stress and characterize natural fractures in terms of permeability.
The analysis of micro-fracturing data consists of two parts: pre-closure analysis and after-closure analysis. The pre-closure analysis involved the analysis of early pressure fall-off data to determine the fracture closure stress of a particular formation at a specific depth. The tests were performed by injecting a small volume of fluid into a small, confined, and isolated zone at low rates to create a small fracture. The closure stress was determined from the analysis of the pressure decline after shut-in. To estimate natural fracture permeability, a series of numerical fully coupled hydro-mechanical simulations of hydraulic fracture propagation was conducted in a naturally fractured reservoir by varying the natural fracture initial permeabilities.
The pressure decline after shut-in of the formation tester pump was analyzed using G-function and square-root-time methods. The point at which the G-function derivative began to deviate downward from the linear trend was identified as the point at which the fracture closes. The cycle of injection and fall-off was repeated four times. After the first cycle, in each subsequent cycle, the fracture pressure was reduced by approximately 20 psi. Based on these four cycles and petrophysical data, a customized model was developed, and poro-mechanical simulations were performed to characterize natural fractures in the formation. The simulation results explain the variation of micro-fracturing pressure history, during the four injection cycles. A comparison of the pressure history from the micro-fracture tests with the injection pressure obtained from the numerical simulation suggested that the formation included relatively impermeable natural fractures.
The characterization of natural fractures during micro-fracturing provides additional information not captured by a traditional G-function or square-root-time analysis. Multiple cycles of injection and pressure fall-off provide a qualitative assessment of in-situ pore pressure and a consistent minimum in-situ stress. Understanding the fracture pressure and natural fractures in the formation is a key component of successful reservoir completion and development. However, challenges exist in the measurement of these reservoir properties with conventional methods of diagnostic fracture injection testing (DFIT™). This new analysis method represents a step forward in terms of overcoming such challenges.
In recent years, viscoelastic surfactants (VES) seemed like an optimum solution for fracturing fluids. The technology was introduced to replace heavily damaging polymers. VES low thermal stability, high cost, and incompatibility with acid additives limited its application in the field. This work aims to investigate the crosslinking of the VES micelles using different shapes of silica and iron oxide nanoparticles to reduce the VES loading and extend its thermal stability.
This work utilized surfactant templating and ultrasonicated co-precipitation methods to produce a specifically tailored mesoporous silica and magnetite nanorods respectively, which were mixed with an anionic VES using ultrasonic bathing. Both spherical and rod-shaped particles of silica and iron oxides were examined to investigate the particle size, shape, and surface charge impact on the degree and the strength of the VES micellization. The studied particles physical properties were assessed using zeta potential, dynamic light scattering (DLS), and transmission electron microscopy (TEM). The rheological performance of the VES mixtures were evaluated at 280 and 350°F through various shearing and heating ramps. The mixture microstructure was investigated using a polarizing microscope before and after the heating process. The produced network between the VES micelles and the nanoparticles were examined using TEM to describe its nature.
The interaction between the nanoparticles and the anionic VES is controlled by the VES concentration, the particle shape, and the temperature range. Although the spherical particles failed to cross link the VES at a concentration of 2 wt%, it succeeded to extend the thermal stability of the VES at a concentration of 4 wt% up to 350°F. The nanorods succeeded to enhance and extend the thermal range of the VES system at only 2 wt% VES. Both shapes of particles performed similarly at 4 wt% VES and up to 280°F. The addition of 7 pptg of silica nanorods extended the thermal stability of the 4 wt% VES, which exhibited and held an apparent viscosity of 200 cp for 2 hours. The addition of rod-shaped particles contributed to stronger micelle to micelle entanglement, especially at VES concentration of 2 wt%. The nanoparticles resulted in secondary networking that contributed positively to the viscosity of the mixture. The rod-shaped particles showed lower thermal stability at 350°F. They maintained 50 cp compared to the total failure of the VES by itself with 10 cp at 350°F. The polarizing microscopy, the TEM, and the DLS analysis showed that the enhancement in the apparent viscosity comes from closely packed structures of nanoparticles in surfactant strings.
This research shows the importance of the selected nanoparticle size, shape, and surface charge on the rheological performance of VES. It lays out a route to synthesize custom built nanoparticles to accommodate the chemistry of surfactants for higher performance and lower cost. This work has implementations in both self-diverting acid systems and fracturing fluids.
In this paper we discuss our studies conducted on two California offshore fields that may be abandoned in near future. The purpose of the study was to examine the feasibility of re-purposing these fields to suitable offshore gas storage by utilizing the reservoir voidage and by using the existing pipeline facilities. These storage sites could offer a significant alternative to the current onshore sites located in highly populated urban areas of California.
Gas storage in certain California offshore fields producing from the fractured Monterey formation could eliminate the potential environmental risks associated with urban onshore storage of gas and prevent incidents such as the October 23, 2015 one in the Aliso Canyon Natural Gas Storage Facility in Los Angeles County. The 100,000 tonnes of methane emitted into the atmosphere resulted in the relocation of thousands of people from the areas proximal to the facility.
Study of the caprock and initial reservoir pressures encountered in these fields shows that a proposed 3000 psi storage pressure is safe for offshore storage purposes. Our computation of voidage caused by more than 3 decades of production shows that on a total basis, under a storage pressure cap of 3000 psi, these two fields together can help in storage of more than 3 TCF of gas. This is about 5 times the existing storage capacity of 0.6 TCF in California. On the long terms basis, the proposed offshore storage fields could provide a secure source of energy for the evolving market of California CNG based transportation, power generation and other consumer needs.
Heavy oil extraction via thermal enhanced oil recovery (EOR) methods is a challenging task due to low mobility of oil at reservoir conditions and high petroleum processing cost due to high impurity content of heavy oils. This task becomes more difficult with the decrease in oil prices. Hence, any effort to decrease the recovery or refinery cost of heavy oil production can make the extraction of these unconventional resources more feasible.
Existing screening criteria tables are still in use to find the optimum thermal EOR methods to recover heavy oil reservoirs. However, since those tables ignore the role of oil and rock compositions in the success and failure of oil recovery through thermal methods, generally the thermal EOR response is different than expected. This study aims to extend existing screening criteria tables for thermal EOR methods by including the impact of oil and rock composition and investigates the produced oil quality originated from different EOR techniques. First, lab-scale steam assisted gravity drainage, in-situ combustion (ISC), steam injection, hot-water injection, and steam/solvent injection experiments were conducted on two different heavy oil samples. The success of each EOR process, the impact of oil type and reservoir rock were interpreted based on the variations between initial and the produced oil viscosity, density, and SARA (Saturates, Aromatics, Resins, and Asphaltenes) fraction content.
Hydrocarbon composition of initial and produced oil samples was compared using Gas Chromatography-Mass Spectrometry (GC-MS). The differences in the molecular signatures were analyzed by a Fourier Transform Infrared (FTIR) Spectroscopy on initial and produced oil samples. GCMS analyses of initial oil samples indicated the biodegradation of the two crude oils were different and they showed high (low lighter component content) and slight (high lighter component content) biodegradation. In terms of produced oil quality, highly biodegraded oil sample responded to ISC better than the slightly biodegraded oil sample. Steam processes upgraded the highly biodegraded oil for the reservoir without clay.
Thermal EOR methods are costly especially at the current price environment. Furthermore, because of the differences in the response of different thermal EOR methods to different reservoirs due to compositional variations in reservoir oil and rock, the thermal EOR methods are not widely applied. Our study is a step taken to improve the existing screening criteria tables to determine the successful thermal EOR candidates through inclusion of oil and rock compositions.
Lost circulation is a very common and expensive problem during drilling and cementing operations in the oil and gas industry. The lost circulation problems encountered during drilling or cementing are a result of one of two factors. These factors are the presence of zones of weak fracture gradients and the presence of high permeability or thief zones downhole. Light weight cements are an effective solution for curbing lost circulation caused by the breakdown of weak zones by conventional cement slurries. This paper presents a discussion of the different methods, additives and technologies that have been and are currently employed in the formulation of lightweight and ultra-lightweight cement slurries for cementing oil wells as well as recent developments based on an extensive literature review. This paper also discusses the mechanical performance, cost effectiveness and field logistical considerations of lightweight slurries formulated using different methods as these are important factors that impact decision making on what slurry extension method to choose for any given scenario.
The information presented in this paper is derived from an extensive review of information contained in papers, journals and books spanning the last 50 years of well cementing and is summarized in such a way that the paper serves as a quick guide to cement slurry extension technology and techniques.
An extensive review of the literature regarding lightweight cements showed that there are three general methods of obtaining lightweight cement slurries. These methods include increasing cement slurry water content (water extension) with the aid of viscocifying agents such as bentonite and sodium metasilicate, adding lightweight materials like glass microspheres and incorporating foam into slurries. Reported test data shows that apart from cement slurries containing glass microspheres and foamed cements, lightweight slurries exhibit lower compressive strength and slower compressive strength development than heavy slurries. Foamed cements pose the greatest design and field logistics challenge while cement slurries with glass microspheres have gained more popularity due to the excellent compressive strength values achievable at ultra-low densities despite their higher cost compared to water-extended slurries and lightweight slurries containing other lightweight additives like fly ash.
The literature review presented also indicates a need for more research into improving lab mixing and testing methods that replicate field applications of foam cement. There is also a need for research into more cost-effective slurry extension additives and technology that exhibit acceptable mechanical performance for well integrity assurance and rheological properties favorable to proper cement placement in the annulus.