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Steam generation for the purposes of thermal recovery includes facilities to treat the water (produced water or fresh water), generate the steam, and transport it to the injection wells. A steamflood uses high-quality steam injected into an oil reservoir. The quality of steam is defined as the weight percent of steam in the vapor phase to the total weight of steam. The higher the steam quality, the more heat is carried by this steam. High-quality steam provides heat to reduce oil viscosity, which mobilizes and sweeps the crude to the producing wells.
Running pulsed-neutron logs in Malaysia has previously been plagued by results with high uncertainties, especially in brown fields with complex multistacked clastic reservoirs. Together with a wide range of porosities and permeabilities, the acquired logs quite often tended to yield inconclusive results. In addition, the relatively fresh aquifer water (where salinity varies from 5,000 to 40,000 ppm) makes reservoir fluid typing and distinguishing between oil and water even more challenging. As a result, the inconsistencies and uncertainties of the results tend to leave more questions than answers. Confidence in using pulsed-neutron logging, especially to validate fluid contacts for updating static and dynamic reservoir models, deteriorated within the various study teams. Due to this fact, the petrophysics team took the initiative to conduct a three-tool log off in one of their wells with the objective of making a detailed comparison of three pulsed-neutron tools in Malaysia’s market today. The main criteria selected for comparisons were the consistency of the data, repeatability, and statistical variations.
With recent advancements in pulsed-neutron (multidetector) tool technology, newer tools are being equipped with more efficient scintillation crystals, improving the repeatability of the measurements as well as the number of gamma ray (GR) count rates associated with the neutron interactions. In addition, the newer tools now have up to five detectors per tool, with the farthest detector supposedly being able to “see” deeper into the formation, albeit at a lower resolution. With these new features in mind, the log off was conducted in a single well with a relatively simple completion string (single tubing, single casing), logged during shut-in conditions only, and the logs were acquired directly one after the other (back to back) to avoid bias to any particular tool.
Both sigma and spectroscopy measurements were acquired to compare the capabilities of each tool. Due to the relatively freshwater salinity, the carbon-oxygen (C/O) ratio from the spectroscopy measurements is used to identify the remaining oil located in the reservoirs, while the sigma measurements determine the gas-oil or gas-water contact, if present.
This paper will illustrate the steps taken by Petronas Carigali Sdn Bhd (PCSB) to compare the raw data and interpreted results from the three pulsed-neutron tools. Consequently, a comparison from all the tools was made to the current understanding of the reservoir assessed. The points from these comparisons will then show which tools are favored over the rest.
Chemical flooding is one of the classical EOR methods, together with thermal methods and gas injection. It is not a new method; indeed, the first polymer flood field pilots date back to the 1950s while the first surfactant-based pilots can be traced back to the 1960s. However, while both gas injection and thermal methods have long been recognised as field proven and are being used at a large scale in multiple fields, it is not the case for chemical EOR.
Although there have been over 500 polymer flood pilots recorded, and almost 100 surfactant-based field tests, large scale field applications are few and far between. This situation seems to be evolving however, as more and more large scale chemical projects get underway. This paper proposes to review the status of chemical EOR worldwide to determine whether it is finally coming of age.
The status of chemical EOR projects worldwide will be reviewed, focusing on recent and current large-scale field developments. This will allow to establish what is working and where the industry is still encountering difficulties. This review will cover North America, South America, Europe, the Middle East, Asia and Africa.
It is clear that polymer flooding is now indeed becoming a well-established process, with many large-scale projects ongoing or in the early stages of implementation in particular in Canada, Argentina, India, Albania and Oman in addition to China. Strangely enough, the US lags behind with no ongoing large-scale polymer flood.
The situation is more complex for surfactant-based processes. At the moment, large-scale projects can only be found in China and – although to a lesser extent – in Canada. The situation appears on the brink of changing however, with some large developments in the early stages in Oman, India and Russia. Still, the economics of surfactant-based processes are still challenging and there is some disagreement between the various actors as to whether surfactant-polymer or alkali-surfactant polymer is the way to go.
This review will demonstrate that polymer flooding is now a mature technology that has finally made it to very large-scale field applications. Surfactant-based processes however, are lagging behind due in part to technical issues but even more to challenging economics. Still there is light at the end of the tunnel and the coming years may well be a turning point for this technology.
Gas to Wire (GTW) is a concept which will aid the UK to meet their growing energy demand as, GTW will allow marginal and somewhat depleted gas fields to convert natural gas to electricity onsite, with the electricity exported via subsea power cables - the concept is not yet fully commercialised offshore. This paper initially discusses what is GTW and then investigates two separate cases: the first focuses on evaluating the viability of GTW for the Kumatage gas field which is 78 km close to shore (located in the Southern North Sea) (
A discussion is also included in GTW's potential to work in conjunction with renewable technologies, such as tying back to Hornsea Project Four which is an offshore windfarm currently under the preapplication stage by Ørsted (hornseaprojects, 2019). It will be approximately 65 km from the Yorkshire coast and will be close to the Theddlethorpe and Bacton gas terminals (National Grid, 2019). By doing so, the electricity produced from Kumatage would need to be exported via a power cable to the windfarm. This study also discusses GTWs compatibility with existing renewable technologies to reduce carbon dioxide (CO2) emissions. By combining the findings of this paper, a further review of the potential of GTWs ability to unlock more marginal and stranded assets and contributing to the security of future UK energy supply. What can also be explored further from this paper is multiphase flow in the reservoir to then be able to model GTW to other offshore gas fields in the SNS.
Cuttings are an undervalued resource that contain vast amounts of relevant formation evaluation (FE) data in the form of entrained volatile chemistries from present day formation liquids/gases. Analysis of these chemistries in cuttings, or other materials (core, side wall core, and muds), enables decisions from well level completions to acreage/basin assessments on an operational timescale. This work compares analysis of rock volatiles to traditional FE (water saturation and permeability) data to demonstrate correlations to field studies in the Delaware Basin and the STACK. The field study from the SCOOP demonstrates how the analysis can be used to drive completion decisions; studies from the STACK demonstrate how the analysis drove acreage assessment and utilization decisions. All cases are presented from nonhermetically sealed samples showing the applicability of the analysis to fresh or legacy materials.
A unique cryo trap-mass spectrometry (CT-MS) system has been developed by Dr. Michael Smith enabling the gentle extraction of volatiles from cuttings, or other materials, and the subsequent identification and quantification of the extracted chemicals. All possible chemistries (hydrocarbons, organic acids, inorganic acids, noble gases, water, etc.) are extracted by gentle volatilization at room temperature under vacuum conditions and concentrated on a CT; the chemistries are separated by warming the CT and volatilizing as a function of sublimation point and then analyzed by MS. Advantages of this CT-MS over GC-MS are that chemicals that would not survive the conditions of a heated GC system can be analyzed and that the analysis does not require different columns as a function of the species type analyzed. The analysis works on both water and oil based mud systems. These results are combined with a geological interpretation to enable application.
The comparison field studies show that the analysis successfully reproduced Sw and permeability trends from petrophysics and sidewall core analysis. The SCOOP field study identifies the mechanism of underproduction in a Hoxbar well and a simple completion strategy for the lateral that would have significantly reduced costs while enabling equivalent production. The STACK field study was utilized by an operator to evaluate and understand the petroleum system across their acreage and enabled unique acreage utilization decisions in terms of well placement and lateral trajectory.
O’Toole, Timothy (Chevron North American Exploration and Production Company) | Adebare, Adedeji (Chevron North American Exploration and Production Company) | Wright, Sarah (Chevron North American Exploration and Production Company)
The Second Bone Spring Sand is currently the second most drilled bench within the Delaware Basin. Some of the main struggles encountered by operators is determining the combined optimal well spacing, targeting, and completions design for a given bench. Moreover, to economically and efficiently develop any bench within the Permian, a strong understanding of reservoir heterogeneity is needed. Recent work has provided insight into the controls on Second Bone Spring Sand (SBSS) production and optimal development strategies. A key driver of well performance is reservoir architecture, and one must understand the spatial variability of their field area as it affects the overall development strategy that is ultimately deployed (i.e. completions design, well spacing, targeting, etc.). Furthermore, a deeper look into completions trends within the SBSS has closed the gap in optimizing dollars spent in relation to production gains.
The Permian Basin of southeast New Mexico and west Texas has been a highlight of North American oil and gas exploration, development, and production for decades. This basin is further sub-divided into the Midland and Delaware Basins (Figure 1), which are separated by the Central Basin Platform. The Delaware Basin is bounded to the east by the Central Basin Platform, to the west by the Diablo Platform, to the north by the northwest shelf and to the south by Marathon-Ouachita orogenic belt.
Formation of the Delaware Basin began with the Tobosa Basin (Galley, 1958) that existed from the Late Pre-Cambrian through the Mississippian, with compression and faulting during the Ouachita-Marathon Orogeny causing the Central Basin Platform to rise (Schumaker, 1992; Soreghan & Soreghan, 2013).
Climate during deposition in the Delaware Basin was generally arid, with the basin resting at approximately 5-10° north of the equator (Soreghan & Soreghan, 2013; Ziegler et al., 1997). Sediment is thought to have been sourced via aeolian transport as well as via fluvial systems (Fischer & Sarnthein, 1988; Soreghan & Soreghan, 2013).
Deposition in the Delaware Basin fluctuated between carbonate-rich highstand and silica-dominated lowstand conditions with high TOC mudstones forming farthest from the shoreline. This reciprocal sedimentation depositional history has led to mixed-lithology rock with highly variable facies, such as the Wolfcamp and Bone Spring Formations that are major targets of unconventional development today. The Leonardian Bone Spring Formation especially displays this lithologic alternation and is comprised primarily of three major siliciclastic members divided by carbonates that are named in order of increasing depth (Figure 2), in addition to regional members such as the Avalon and Harkey Mills Sandstone. This paper focuses on the middle siliciclastic member, the Second Bone Spring Sand (SBSS), which was deposited as a lowstand submarine fan system.
Pingo, Abraham (Graña Montero Petrolera S.A) | Soriano, Victor Hugo (Graña Montero Petrolera S.A) | Villanueva, Jaime (Consultor Independiente) | Jimenez, Edgar (CPVEN Servicios Petroleros S.A.C) | Vasquez, Elvis (CPVEN Servicios Petroleros S.A.C) | Ahmed, Ramadan (University of Oklahoma)
In the Talara basin, the cementing of the production section represents a challenge to achieve effective zonal isolation around the pay zone and ensure an efficient hydrocarbon production. For this purpose, well cement design must be tailored to accomplish specific goals. Challenges related to depleted intercalation zones, gas-bearing formation, highly recycled drilling mud, and marginal economic incentives push operators to build a multidisciplinary team with cementing and drilling fluid service companies to optimize well cement design. The objective of this article is to present cementing lessons learned from a recent drilling campaign in the Peruvian northwest area.
Cementing jobs in the Block IV of the Peruvian northwest area is usually complex due to poor zonal isolation according to cement bond evaluation tools (sonic logs). The lack of good cement quality is related to micro-channeling and loss of well integrity. In fact, things get more complicated due to the requirement of recycling of the drilling mud to cut costs. Highly recycled mud sticks to the formation walls, complicating its removal. Various measures have been taken to understand the issues behind poor cementing jobs. Proper cementing design and placement through continuous improvements in both drilling fluid and cement formulations resulted in successful cement placements with consistent outcomes in several wells.
The formulation and designing of the pre-flushes, and the optimization of their rheological properties and wellbore exposure time, resulted in effective mud removal. For an 8.5 in hole, which was cased with a 5.5 in casing, the minimum wellbore exposure time of the pre-flush considered in the design was 2.5 minutes, each ending with a washer allowing the mud cake to disperse. Centralization was kept high with a standoff greater than 85%. The slurry design considered 14.7 ppg tail and 14.2 ppg lead slurries specifically tailored for the current conditions. Also, mechanical reciprocation of the casing string for about 10 ft-long strokes enabled more effective mud removal. Excellent results were obtained by the cement bond log based on the sonic principle. This log was taken 72 hours after the cementing job showed a 10 mV reduction in amplitude through the entire target zone, resulting in a 90% bonding index.
The challenges related to the cementing complexities were finally overcome with a multidisciplinary team of engineers from both operating and service companies working together diligently. During this process, a low-cost and effective cementing job design was developed through continuous improvement. The design resulted in good repeatability and consistency in the cementing job.
The screening of chemical EOR technologies for a Colombian field was performed using two different screening tools (weighting averages and artificial intelligence). The Alkali-Surfactant-Polymer (ASP) pilot results were compared with the initial screening studies identifying some weaknesses that are addressed in this paper. Additionally, the use of Lattice Boltzmann pore-scale flow simulation approach to support EOR screening studies is also presented.
The screening study was developed using the same input data (e.g. pressure, temperature, porosity, permeability, oil gravity, and viscosity). Screening results and potential reservoir analogs identified using both systems were compared, including the evaluation of the geological parameters that are normally missing in most of screening studies. The results are compared with the ASP pilot performance to validate the effectiveness of conventional screening studies overlooking geologic information. In addition, the results were also confirmed evaluating ASP field cases reported in the literature. Finally, the use of digital rock analysis using micro CT scan images to support ongoing screening results is presented.
Screening results obtained using different screening tools were similar identifying the EOR recovery process (e.g. Chemical EOR). However, the screening results excluding the evaluation of geological parameters such as rock cementation (e.g. sandstone formations with carbonate cement) did not prevent the selection of ASP flooding as an EOR recovery process for the field under study. This was confirmed with the severe scaling problems observed during the ASP pilot test implemented in Colombia as well in Canadian ASP floods. This paper describes the main steps for conducting robust EOR screening studies, including the use of Lattice Boltzmann pore-scale flow simulation to evaluate preliminary performance of oil recovery processes (e.g. waterflooding, polymer and surfactant injection) that contributes to field evaluations and experimental lab design.
The proposed screening approach will contribute identifying the technical and economic EOR potential (from exploratory appraisal to mature field rejuvenation) under conditions of limited information and time constraints.
Hill, A. D. (Texas A&M University) | Laprea-Bigott, M. (Texas A&M University) | Zhu, D. (Texas A&M University) | Moridis, G. (Texas A&M University) | Schechter, D. S. (Texas A&M University) | Datta-Gupta, A. (Texas A&M University) | Abedi, S. (Texas A&M University) | Correa, J. (Lawrence Berkeley National Laboratory) | Birkholzer, J. (Lawrence Berkeley National Laboratory) | Friefeld, B. M. (Class VI Solutions, Inc.) | Zoback, M. D. (Stanford University) | Rasouli, F. (Stanford University) | Cheng, F. (Rice University) | Ajo-Franklin, J. (Rice University / Lawrence Berkeley National Laboratory) | Renk, J. (Department of Energy) | Ogunsola, O. (Department of Energy) | Selvan, K. (INPEX Eagle Ford LLC)
The Eagle Ford Shale Laboratory is a DOE and industry-sponsored multi-disciplinary field experiment aimed at applying advanced diagnostic methods to map hydraulic fractures, proppant distribution, and the stimulated reservoir volume. The field site is an Inpex Eagle Ford, LLC lease in LaSalle county, Texas that has a legacy Eagle Ford producing well and that will be developed with 5 new producers. Utilizing newly-developed monitoring technologies, the project team will deliver unprecedented comprehensive high-quality field data to improve scientific knowledge of three important processes in unconventional oil production from shales: (1) a re-fracturing treatment in which the previously fractured legacy well will be re-stimulated for improved production, (2) a new stimulation stage where the most advanced hydraulic fracturing and geosteering technology will be applied during zipper-fracturing of 3 new producers, and (3) a Gas-Injection Enhanced Oil Recovery (EOR) Phase where one of the wells will be later tested for the efficiency of Huff and Puff gas injection as an EOR method. Field monitoring is being complemented with laboratory testing on cores and drill cuttings, and coupled modeling for design, prediction, calibration, optimization, and code validation. The multi-disciplinary team consists of researchers from Texas A&M University, Lawrence Berkeley National Laboratory, Stanford University, Rice University, and Inpex Eagle Ford, LLC.
The ultimate objective of the Eagle Ford Shale Laboratory Project is to help improve the effectiveness of shale oil production by providing new scientific knowledge and new monitoring technology for both initial stimulation/production as well as enhanced recovery via re-fracturing and EOR. The main scientific/technical objectives of the project are:
Build and test active seismic monitoring with fiber optics in an observation well to conduct: (1) real-time monitoring of fracture propagation and stimulated volume, and (2) 4D seismic monitoring of reservoir changes during initial production and during an EOR pilot.
Test distributed temperature sensing (DTS), distributed acoustic sensing (DAS) and distributed strain sensing (DSS) with fiber optic technology and develop protocols for field application.
Assess spatially and temporally resolved production characteristics and explore relationships with stimulated fracture characteristics by open hole logging, cased hole logging, production logging, and tracer technology.
Understand rock mechanical properties and reservoir fluid properties and their effect of stimulation efficiency through coring and core analysis.
Evaluate suitability of re-fracturing to achieve dramatic improvements in stimulated volume and per well resource recovery.
Develop understanding of gas-based EOR Huff and Puff methods to increase per well resource recovery by lab tests and field test.
In certain wells where relatively high levels of iron are present, the use of polyacrylamide-based friction reducers (FR) for hydraulic fracturing completions can lead to poor performance and negative chemical interactions including the formation of unusual semi-solid accumulations. The accumulations, often referred to as "gummy bears" due to their rubbery texture, can form in surface and downhole equipment and can inhibit well production. This paper summarizes work performed to evaluate the performance of FRs in the presence of iron, identifies the specific causal factors for the formation of the accumulations, and provides practical solutions to mitigate the problems associated with the negative iron impact in order to improve overall well performance.
Iron can present itself during fracturing operations in different forms and from different possible sources including source water, tubulars, and within the rock formations themselves. To study the interactions between iron sources and anionic friction reducers, synthetic and field water sources were used to identify and quantify the negative effects that iron has on performance parameters for FRs and viscosifying friction reducers (VFR) such as friction reduction, viscosity development and the development of polymer accumulations. The second portion of this paper is given to identify methods to improve overall FR performance and to mitigate the risk of developing the accumulations in iron-rich environments. Field case histories are presented to support the results of this work.
Over the years, the oil and gas industry has documented many of the detrimental effects that iron can have on well completion operations. Iron sulfide scale, for example, is the result of hydrogen sulfide and iron interacting with each other and can lead to problematic issues including loss of injectivity in water injection and disposal wells, plugging of artificial lift mandrels and perforations, reduced reservoir permeability, and other mechanisms that can limit overall well production (Nasr-El-Din et al, 2001). In hydraulic fracturing operations, the presence of iron can also have negative effects on the performance of fracturing fluids. Many, if not most, of the polyacrylamide polymers used in fracturing operations are negatively charged (anionic) in nature. When positively charged ions such as calcium (Ca2+), magnesium (Mg2+), ferrous iron (Fe2+), or ferric iron (Fe3+) come into contact with the negatively charged polymer, the result is usually a reduction in the overall performance of the polymer.