Fiber optic technology has been used in several wells at an oilfield to measure strain to monitor overburden deformation. The application of this technology involved a series of bench tests and field tests to gather some key learnings to enhance well design, well construction, and fiber optic operation. Prior to installation of the fiber optic, a series of bench tests were conducted to evaluate the coupling of fiber with the capillary lines to determine its impact on the measurement of strain. The testing demonstrated that anchoring the fiber at the top and bottom of the capillary line was sufficient to hold the fiber in place and enabled the effective measurement of strain along the length of the well, which was proven when applied to field conditions. To enhance well design for strain measurement, several wells had fiber optic capillary lines installed on the inside and outside of casing to investigate the potential dampening effect due to fiber being located inside a string of casing. This was used to determine the optimal casing string to install fiber optic to measure strain in the overburden. Additionally, a novel concept was utilized in the well design that involved using the fiber optic capillary clamps as borehole centralizers, which resulted in equipment and rig cost savings. The details of the bench tests, well design, operational experience, and their associated lessons learned are presented.
Globally, most oil fields are on the decline and further production from these fields is addressed to be practical in cost-effectiveness and oil productivity. Most oil companies are adopting two main technologies to address this: artificial intelligence and enhanced oil recovery (EOR). But the cost of some of these EOR methodologies and their subsequent environmental impact is daunting. Herein, the environmental and economic advantage of microbial enhanced oil recovery (MEOR) makes it the point of interest. Since, there is no need to change much-invested technology and infrastructure, amidst complex geology during MEOR application, it is entrusted that MEOR would be the go-to technology for the sustainability of mature fields.
Despite the benefits of MEOR, the absence of a practical numerical simulator for MEOR halts its economic validation and field applicability. Hence, we address this by performing both core and field- scale simulations of MEOR comparing conventional waterflooding. The field scale is a sector model(fluvial sandstone reservoir with 13,440 active grid cells) of a field in Asia - Pacific.
Here we show that pre-flush inorganic ions (Na+ and Ca2+) affect the mineralization of secondary minerals which influences microbe growth. This further influences carboxylation, which is relevant for oil biodegradation. Also, as per the sensitivity analysis: capillary number, residual oil saturation and relative permeability mainly affect MEOR. Secondary oil recovery assessment showed an incremental 6% OOIP for MEOR comparing conventional water flooding. Also, tertiary MEOR application increased the oil recovery by about 4% OOIP over conventional water flooding. It was established that during tertiary recovery, initiating MEOR after 5years of conventional waterflooding is more advantageous contrasting 10 and 15years. Lastly, per probabilistic estimation, MEOR could sustain already water-flooded wells for a set period, say, a 20% frequency of increasing oil recovery by above 20% for 2 additional years as highlighted in this study.
Green fields today mostly can be regarded as marginal fields and successfully developed. It covers the complete assessment of the oil and gas recovery potential from reservoir structure and formation evaluation, oil and gas reserve mapping, their uncertainties and risks management, feasible reservoir fluid depletion approaches, and to the construction of integrated production systems for cost effective development of the green fields. Depth conversion of time interpretations is a basic skill set for interpreters. There is no single methodology that is optimal for all cases. Next, appropriate depth methods will be presented. Depth imaging should be considered an integral component of interpretation. If the results derived from depth imaging are intended to mitigate risk, the interpreter must actively guide the process.
With the current applications of CO2 in oil wells for enhanced oil recovery (EOR) and sequestration purposes, the dissolution of CO2 in the formation brine and the formation of carbonic acid is a major cause of cement damage. This degradation can lead to non-compliance with the functions of the cement as it changes compressive and shear bond strengths and porosity and permeability of cement. It becomes imperative to understand the degradation mechanism of cement and methods to reduce the damage such as the addition of special additives to improve the resistance of cement against acid attack. Hence, the primary objective of this study is to investigate the effects of hydroxyapatite on cement degradation.
To investigate the impacts of hydroxyapatite additive on oil well cement performance, two Class H cement slurry formulations (baseline/HS and hydroxyapatite containing cement/HHO) were compared after exposure to acidic environments. To evaluate the performance of the formulations, samples were prepared and aged in high-pressure high-temperature (HPHT) autoclave containing 2% brine saturated with mixed gas containing methane and carbon dioxide. Tests were performed at different temperatures (38 to 221°C), pressures (21 to 63 MPa) and CO2 concentrations (10 to 100%). After aging for 14 days at constant pressure and temperature, the samples were recovered and their bond and compressive strength, porosity and permeability were measured and compared with those of unaged samples.
The results demonstrated that adding hydroxyapatite limits carbonation. Baseline samples that do not contain hydroxyapatite carbonated and consequently their compressive strength, porosity, permeability, and shear bond strength significantly changed after aging while hydroxyapatite-containing samples displayed a limited change in their properties. However, hydroxyapatite-containing samples exhibit high permeability due to the formation of microcracks after exposure to carbonic acid at high temperature (221°C). The formation of microcracks could be attributed to thermal retrogression or other phenomena that cause the expansion of the cement.
This article sheds light on the application of hydroxyapatite as a cement additive to improve the carbonic acid resistance of oil well cement. It presents hydroxyapatite containing cement formulation that has acceptable slurry properties for field applications and better carbonic acid resistance compared to conventional cement.
Investigation of the effectiveness of matrix stimulation treatments for removing drilling induced damage in Akita region in northern Japan is of interest due to the presence of large quantities of acid-sensitive minerals, such as analcime. Feasibility study of the sub-commercial field redevelopment in the Kita-Akita oil field, one of the satellite fields of main Yabase oil fields, which produced from 1957 to 1973, and were plugged and abandoned, were conducted. As a part of the studies, matrix acidizing laboratory experiments were performed. Conventional mud acids and formic-based organic mud acid systems cause significant permeability damage due to instability of analcime in these acids. This study focuses on the development of a treatment fluid that removes drilling-induced damage and is also compatible with the formation.
Petrology studies and core flow tests were used in conjunction with geochemical modeling to achieve this objective. A petrographic analysis on the untreated cores showed abundant tuffaceous pore-filling mineral phases, ranging from 12 to 20% in volume. Smectite clay and microcrystalline quartz are the major constituents as alteration products of volcanic glass. Analcime was present in significant quantities in all samples tested.
Six core flow tests were performed on formation cores to optimize the acid preflush and main acid stage. Permeability change due to the treatment fluids was recorded for the tests. Chemical analysis of the effluent was performed on three core flow tests. Core samples before and after acidization were characterized based on thin section, X-ray diffraction (XRD), scanning electron microscopy(SEM) and mineral mapping.
Core flow tests with a conventional retarded organic mud acid resulted in only a 75% retained permeability. The permeability damage by the retarded organic mud acid was surprising because it usually performs well in acid-sensitive formations. A chelant based retarded mud acid was tested next and resulted in minor formation damage. It can potentially be used in a field treatment as its high dissolving power is expected to more than compensate for the damage. The highest retained permeability was obtained with an acetic-HF acid system. It was successfully able to remove drilling-induced damage and was also compatible with the native mineralogy. Core flow tests were used to calibrate permeability-porosity relationship used in the geochemical simulator. The geochemical simulator was then used to predict field-level acid response.
The analytic methods presented are general enough to be of interest to sandstone acidizing studies where detailed analysis is needed for damage identification and removal. The fluids developed for this formation area good candidates for other formations where conventional acid systems have not performed well. This study also highlights close collaboration between an operator and service company to find a workable solution to a challenging stimulation requirement.
Nielsen, Julie (The Danish Hydrocarbon Research and Technology Centre, Technical University of Denmark) | Poulsen, Kristoffer G. (Department of Plant and Environmental Sciences, University of Copenhagen) | Christensen, Jan H. (Department of Plant and Environmental Sciences, University of Copenhagen) | Solling, Theis I. (Center for Integrative Petroleum Research, College of Petroleum Engineering & Geoscience, King Fahd University of Petroleum and Minerals)
Mature fields often times surprise with respect to the production from the various wells across reservoir sections. This is for example the case in a tight chalk field that we have used as a case study for newly developed technique that employs oil finger printing in the analysis of production data. A small subset of wells has been found to produce significantly better than the remainder and we set out to explore whether the root cause is that there is a connection to higher lying reservoir sections through natural or artificial fractures. This was done with advanced analytical chemistry (GC-MS) and a principal component analysis to map differences between key constituents of the oil from wells across the reservoir section. The comparative parameters are mainly derived from biomarker properties but we also developed a way to directly include production numbers. The approach provides means to correlate the molecular properties of the oil with the production and the general composition that determines density and adhesive (to the rock) properties. Thus, the results provide a new angle on the flow properties of the oil and on the charging history of the reservoir. It is clear from the analysis that the subset of wells does not produce better because of a connection to an upper reservoir section that contributes to the production with oil of a different composition because the molecular mix is indeed quite similar in each of the investigated wells. It is not possible to rule out that there is a connection to an upper-lying section with oil from the same source. One aspect that does differs across the field is the ratio of heavy versus light molecules within each group of molecules and the results show that the region that produce better has the lighter components. We take that to indicate that the lighter components come from oil that flows better and thus is produced more easily. The reservoir section with the lighter oil also lies higher on the structure and is therefore must likely to have been charged first so part of the favorable production seems to be a matter of "first in" "first out". A GC-MS approach such as the one proposed here is cost-effective, fast and highly promising for future predictions on where to perform infill campaigns because the results are indicative of charging history and flow properties of the oil.
Is Surfactant Environmentally Safe for Offshore Use and Discharge? The current presentation date and time shown is a TENTATIVE schedule. The final/confirm presentation schedule will be notified/available in February 2019. Designing Cement Jobs for Success - Get It Right the First Time! Connected Reservoir Regions Map Created From Time-Lapse Pressure Data Shows Similarity to Other Reservoir Quality Maps in a Heterogeneous Carbonate Reservoir. X. Du, Y. Jin, X. Wu, U. of Houston; Y. Liu, X. Wu, O. Awan, J. Roth, K.C. See, N. Tognini, Shell Intl.
By International Petroleum Technology Conference (IPTC) Monday, 25 March 0900-1600 hours Instructors: Olivier Dubrule and Lukas Mosser, Imperial College London Deep Learning (DL) is already bringing game-changing applications to the petroleum industry, and this is certainly the beginning of an enduring trend. Many petroleum engineers and geoscientists are interested to know more about DL but are not sure where to start. This one-day course aims to provide this introduction. The first half of the course presents the formalism of Logistic Regression, Neural Networks and Convolutional Neural Networks and some of their applications. Much of the standard terminology used in DL applications is also presented. In the afternoon, the online environment associated with DL is discussed, from Python libraries to software repositories, including useful websites and big datasets. The last part of the course is spent discussing the most promising subsurface applications of DL.
Takabayashi, Katsumo (INPEX) | Shibayama, Akira (INPEX) | Yamada, Tatsuya (ADNOC Offshore) | Kai, Hiroki (INPEX) | Al Hamami, Mohamed Tariq (ADNOC Offshore) | Al Jasmi, Sami (ADNOC Offshore) | Al Rougha, Hamad Bu (ADNOC Offshore) | Yonebayashi, Hideharu (INPEX)
This study aims to improve asphaltene-risk evaluation using long-term data. Temporal changes in asphaltene risks with gas injection were evaluated. In reservoirs under gas injection, the in-situ fluid component gradually changes by multiple contact with the injected gas. Those compositional changes affect asphaltene stability, causing difficulty in risk prediction using asphaltene models. This study aims to reduce the risk uncertainty depending on operational-condition changes.
Periodic upgrading of asphaltene models is essential for understanding the time-dependent changes of asphaltene risks. In a previous study, the asphaltene risk was evaluated for an offshore oil field in 2008 using the cubic-plus-association equation-of-state (EOS) models and using all the available data at the time. Additional experimental data were subsequently collected for a gas-injection plan. An additional study was performed that incorporated and compared the data sets.
According to the previous study recommendation, additional asphaltene laboratory studies were conducted using the newly collected samples. All the asphaltene-onset pressures (AOPs) detected in the new samples were higher than those found in the previous study. A large difference was observed between the past and recent AOPs in the lower reservoir even though the samples were collected from the same well. The asphaltene-precipitation risk increases considerably because the new study detected AOP at the reservoir temperature, whereas no AOPs were detected in the previous study. The difference may be attributed to saturation-pressure increase. Next, the numerical asphaltene models were revised; the re-evaluated asphaltene-risk estimations were higher in the lower reservoir and slightly higher in the upper reservoir than the past ones. The reference sample fluids were collected from two different wells with different asphaltene and methane (C1) contents. The reliability of the new asphaltene laboratory results was increased by applying multiple data interpretation. Thus, the difference between the past and recent results can be attributed to fluid alteration with time. On the basis of the analysis in this study, the risk rating was updated to slightly higher than in the previous evaluation, emphasizing the importance of regular monitoring of asphaltene risks.
This study provides valuable findings of time-lapse evaluation of asphaltene-precipitation risks for a reservoir under gas injection. The evaluations currently conducted in the industry are snapshots of instantaneous risks. Through the entire field life, the risks have varied depending on the operating conditions. This study demonstrates that risk estimates can change in a unique field with identical work flow by analyzing data collected at different times. Finally, this study demonstrates the importance of time-dependent reservoir-fluid properties.
Temizel, Cenk (Aera Energy) | Irani, Mazda (Ashaw Energy) | Canbaz, Celal Hakan (Schlumberger) | Palabiyik, Yildiray (Istanbul Technical University) | Moreno, Raul (Smart Recovery) | Balikcioglu, Aysegul (USC) | Diaz, Jose M. (VCG O&G Consultants) | Zhang, Guodong (China Petroleum Eng and Construction Corp.) | Wang, Jie (College of Technological Studies) | Alkouh, Ahmad
As major oil and gas companies have been investing in renewable energy, solar energy has been part of the oil and gas industry in the last decade. Originally, solar energy was seen as a competing form of energy source as a threat that may replace or decrease the share of fossil fuels as an alternative energy resource in the world. However, oil and gas industry has adapted to the wind of change and has started investing and utilizing the solar energy significantly. In this perspective, this study investigates and outlines the latest advances, technologies, potential of solar both as an alternative and a complementary source of energy in the Middle East in the current supply and demand dynamics of oil and gas resources.
A comprehensive literature review focusing on the recent developments and findings in the solar technology along with the availability and locations are outlined and discussed under the current dynamics of the oil and gas market and resources. Literature review includes a broad spectrum that spans from technical petroleum literature with very comprehensive research to non-technical but renowned resources including journals and other publications including raw data as well as forecasts and opinions of respected experts. The raw data and expert opinions are organized, summarized and outlined in a temporal way within its category for the respective energy source.
Solar energy is discussed from a perspective of their roles either as a competing or a complementary source to oil and gas. In this sense, this study goes beyond only providing raw data or facts about the energy resources but also a thorough publication that provides the oil and gas industry professional with a clear image of the past, present and the expected near future of the oil and gas industry as it stands with respect to renewable energy resources.
Among the few existing studies that shed light on the current status of the oil and gas industry facing the development of the renewable energy are up-to-date and the existing studies within SPE domain focus on facts only lacking the interrelationship between solar energy and oil and gas such as solar energy used in oil and gas fields as a complementary green energy.