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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 183329, “Downhole Sand-Ingress Detection With Fiber-Optic Distributed Acoustic Sensors,” by Pradyumna Thiruvenkatanathan, Tommy Langnes, Paul Beaumont, Daniel White, and Michael Webster, BP, prepared for the 2016 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 7–10 November. The paper has not been peer reviewed.
There is currently no proven technology available in the market that accurately identifies downhole sand-ingress locations in real time. In this paper, the authors present results from use of a new technology that uses in-well-conveyed fiber-optic distributed acoustic sensing (DAS) for the detection of sand-ingress zones across the reservoir section throughout the production period in real time.
Mechanical sand-control systems are not always fully effective. The end result may be high sand production, which results in choking back the well and reducing hydrocarbon production significantly. In most cases, the precise sanding interval is unknown, making sand-remediation operations (such as remedial plug placements) often ineffective. A successful remediation requires identification of locations of sand entry to inform targeted sand-shutoff operations. However, no proven technology accurately identifies sand-ingress locations during well production in real time.
The technology described in this paper has now been used successfully
While conventional surface acoustic sand detectors provide a delayed indication of onset of downhole sanding events, they do not provide information about the zones in the reservoir that are producing sand. A successful sand-shutoff operation, however, requires knowledge and definitive identification of the zones (or depth sections) in the reservoir contributing to sanding and their relative concentrations.
DAS has been viewed as a potential candidate technology for downhole sand detection in recent years. DAS systems are intrinsic optical-fiber-based acoustic-sensing systems that use the backscatter component of the light injected into an optical fiber to detect acoustic perturbations along the length of the fiber. The fiber itself acts as the sensing element, with no additional transducers in the optical path, and measurements are taken along the length of the entire fiber, allowing for a true distributed measurement using a single fiber. The technology provides sensitivity to strain variations by monitoring changes in the length and index of refraction of the fiber induced by impinging acoustic pressure waves.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 185030, “Improved Oil Recovery in Tight Oil Formations: Results of Water-Injection Operations and Gas-Injection Sensitivities in the Bakken Formation of Southeast Saskatchewan,” by S.M. Ghaderi, C.R. Clarkson, and A. Ghanizadeh, University of Calgary, and K. Barry and R. Fiorentino, Crescent Point Energy, prepared for the 2017 SPE Canada Unconventional Resources Conference, Calgary, 15–16 February. The paper has not been peer reviewed.
Although improvement in hydraulic-fracture properties and infill drilling remains the focus of recovery enhancement from the Bakken, low oil recoveries and steep initial decline rates are experienced in primary-recovery operations, even after application of multifractured-horizontal-well technology. Therefore, many pilots have been executed to determine the viability of waterflooding for maintaining oil rates and improving recoveries through reservoir-pressure maintenance and sweep-efficiency enhancement. This paper presents the performance results from one of the waterflood pilots in the Viewfield Bakken.
A section of the Bakken reservoir (the geology of which is described in detail in the complete paper) deemed to be representative of the waterflood performance in Viewfield is considered for modeling. This section has been developed by use of multifractured horizontal wells completed in the Middle Bakken (main target reservoir) with a well spacing of 200 m (eight wells per section, named A through H). All eight wells started oil production within a similar time frame, and, after approximately 1 year of production, every other well was converted to a water injector.
Reservoir-Fluid Model. Conventional pressure/volume/temperature (PVT) analysis was conducted by a commercial laboratory on 12 surface-separator oil and gas samples. Recombination of fluids at reservoir temperature (156.2°F) yields a final gas/oil ratio of 810 scf/STB. Subsequently, a series of constant-composition-expansion and differential-liberation tests was conducted on the recombined fluid to determine oil-saturation pressure, oil-formation-volume factor, oil density, and oil and gas viscosity as a function of pressure. The Peng-Robinson equation of state and modified Pedersen viscosity correlation were tuned to replicate the PVT properties of oil and gas as a function of pressure.
Reservoir Grid Model. On the basis of the well tops and reservoir net-pay values, reservoir structure for the study area was generated. It is known that the minimum horizontal stress is aligned in the northwest direction and at approximately 50° with respect to the east/west horizon. Therefore, reservoir gridding is rotated at this angle to mimic the hydraulic-fracture orientation along the horizontal-well laterals. Grid size in the horizontal direction is 65×65 ft, and the total thickness of the reservoir is approximately 28 ft, which is divided into nine layers of equal thickness.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 185076, “Imbibition Oil Recovery From Tight Rocks With Dual-Wettability Pore Networks: A Montney Case Study,” by Ali Javaheri and Hassan Dehghanpour, SPE, University of Alberta, and James Wood, SPE, Encana, prepared for the 2017 SPE Canada Unconventional Resources Conference, Calgary, 15–16 February. The paper has not been peer reviewed.
Previous studies demonstrate that Montney rock samples present a dual-wettability pore network. Recovery of the oil retained in the small hydrophobic pores is uniquely challenging. In this study, the authors applied dual-core-imbibition (DCI) methods on several Montney core plugs and introduced the imbibition-recovery (IR) trio to investigate the recovery mechanisms in rocks with dual-wettability pore networks.
Spontaneous imbibition of aqueous phases (water, brine, or surfactant solutions) in fractured sandstone has been studied as a possible mechanism for enhanced oil recovery. Extensive experimental and mathematical investigations have been conducted for relating the imbibition rate and total oil recovery to the capillary and gravity forces and geometrical parameters. However, rock/fluid interactions in tight and shale reservoirs are more complicated than those seen in conventional reservoirs. In addition to capillary forces, organic materials and reactive clay minerals can inﬂuence the fluid ﬂow and storage in the small pores of low-permeability rocks. The affinity of reservoir rock to a particular fluid in such formations depends especially on rock mineralogy and properties of the organic matter that coats and fills the pores.
Previous comparative imbibition tests show that the affinity of the Montney samples to oil is significantly higher than their affinity to water. This behavior was explained by the presence of water-repellent pores within or coated by solid bitumen or pyrobitumen. In the complete paper, the authors focus on imbibition oil recovery of samples cored from the Montney Formation and investigate the role of rock-fabric complexities, such as dual-wettability characteristics, in oil recovery by water imbibition. A detailed discussion of materials used in the spontaneous-imbibition and oil-recovery tests, including rock and fluid properties, is included in the complete paper.
The authors conducted three sets of comparative tests on five twin core plugs, which were dry cut from Montney cores. The samples are characterized by measuring mineral concentration, total-organic-carbon (TOC) content, porosity, and permeability. The methodology is fully described in the complete paper.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 181361, “Advancement in Openhole Sand-Control Applications With Shape-Memory Polymer,” by Xiuli Wang and Gbenga Osunjaye, Baker Hughes, a GE company, prepared for the 2016 SPE Annual Technical Conference and Exhibition, Dubai, 26–28 September. The paper has not been peer reviewed.
Conventional openhole sand-control techniques include standalone screens, expandable screens, and openhole gravel packing (OHGP). In some cases, the uniformity, size, and level of compressive strength of the formation dictate the use of an OHGP completion. However, OHGP is not always feasible or practical for some reservoirs and geographic locations. Shape-memory-polymer (SMP) technology can fill the gaps that exist with current OHGP techniques. This paper summarizes a technology using SMP to provide downhole sand control in openhole environments.
The SMP conformable sand-control system consists of an engineered polymer material compacted onto a retainer cartridge (outer shroud, plain Dutch-weave mesh, and inner shroud). The assembly is then installed onto a perforated base pipe by mechanical means to provide a simple modular system for openhole sand-control applications.
SMP Principle and Engineered Behaviors. The SMP typically has two different states: the glass state at low temperatures and the rubber state at higher temperatures. The point of change of state (the transition from the glass state to the rubber state), and the associated temperature, is referred to as the glass transit temperature (Tg).
The engineered SMP has a defined Tg—the point where shape recovery starts. The initial SMP is first heated to the Tg of the polymer. Then, a mechanical force is applied to compact it to a smaller diameter and onto a retainer cartridge. The condensed SMP is then cooled below its Tg, and the force is removed. The SMP retains its compacted size until the surrounding temperature of the SMP reaches the Tg, at which point shape recovery begins.The bottomhole temperature (BHT) of the candidate reservoirs needs to be lower than the Tg to ensure that the SMP is rigid under the downhole conditions during the production phase. After the SMP sand-control system is installed in a wellbore, to expand the SMP under a BHT that is lower than the Tg, an activation fluid must be introduced. This activation fluid serves as a catalyst and temporarily reduces the Tg below the BHT so the SMP will be recovered to its initial shape. After the SMP is deployed, the activation fluid is flushed out. The SMP retains its recovered shape that conforms to the wellbore, and it is ready for production.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 185032, “Enhance Microscopic Sweep Efficiency by Use of Smart Water in Tight and Very Tight Oil Reservoirs,” by T. Kadeethum, H.K. Sarma, and B.B. Maini, University of Calgary, prepared for the 2017 SPE Canada Unconventional Resources Conference, Calgary, 15–16 February. The paper has not been peer reviewed.
In the literature, improvement of oil recovery in smart-water-injection schemes has been shown to be mediated by wettability alteration. This process reduces residual oil saturation, which, in turn, affects microscopic sweep efficiency and leads to subsequent enhancement of overall waterflood performance. Currently, there are few studies on smart waterflooding in tight and very tight oil reservoirs. This work examines smart-waterflood opportunities in such reservoirs.
Residual-oil-saturation reduction improves microscopic sweep efficiency and, therefore, overall waterflood performance. Furthermore, decreasing endpoint water relative permeability diminishes mobility of the water phase such that water production is similarly reduced. Though these circumstances improve oil-production behavior, the primary parameters that lead to this improvement are still not well-understood.
Among the statistically significant parameters that can influence smart-waterflood performance is clay content. One plausible explanation for the strong correlation between clay content and oil recovery is the positive correlation between cation-exchange capacity (CEC) and clay content. With higher CEC values, more rock surface may be charged. This results in either the expansion or compression of the double layer, which also induces a wettability alteration. Although tight oil reservoirs have limited flow capability, high CEC values in these reservoirs facilitate the wettability-alteration process. The objectives of the complete paper are to ex-amine the smart-waterflood potential in tight and very tight oil reservoirs, and to identify the CEC effect on smart-water-injection performance. The complete paper provides a discussion of the methodology (procedures and strategies) of the study.
The literature contains evidence of smart-waterflood performance, with some works demonstrating that smart water improves oil recovery by reducing residual oil saturation. Furthermore, it decreases the endpoint water relative permeability. Smart water also improves microscopic sweep efficiency, leading to overall waterflooding efficiency.
There is a distinct effect of porosity mean and porosity variance on CEC; there is furthermore a profound effect of CEC upon smart-water performance. Simulation properties relevant to the CEC effect are shown in Table 3 of the complete paper. There are two main types of fluid composition: in-situ fluid composition, which is the initial fluid in the reservoir at timestep zero, and the injected-fluid composition, which is the fluid that is forced into the reservoir at timestep greater than zero. Three homogeneous-reservoir cases with varying CEC values are considered.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 27183, “Current State of the One-Trip Multizone Sand-Control-Completion System and the Conundrum Faced in the Gulf of Mexico Lower Tertiary,” by Bruce Techentien, Tommy Grigsby, and Thomas Frosell, Halliburton, prepared for the 2016 Offshore Technology Conference, Houston, 2–5 May. The paper has not been peer reviewed. Copyright 2016 Offshore Technology Conference. Reproduced by permission.
This paper provides perspective on the current state of multizone completion technology and issues encountered in the industry with developing a system that offers increased capabilities to meet the increasing challenges presented by the Lower Tertiary in the Gulf of Mexico (GOM). The multizone technology has proved to be an enabler for cost-efficient completions in the shallow-well environment and in the high-cost ultradeepwater environment requiring high-rate fracture-stimulation treatments.
Lower Tertiary GOM
The Lower Tertiary play is south and west of the Miocene area in the GOM and is, consequently, in deeper water. The Lower Tertiary is located approximately 175 miles offshore and is estimated at 80 miles wide and up to 300 miles long. Water depths are from 5,000 to 10,000 ft. Production targets are at depths of 10,000 to 30,000 ft subsea.
The Tertiary trend is from 66 million to 38 million years old. Within the Lower Tertiary, the Lower Wilcox portion presents sheet to amalgamated-sheet sands considered to be part of a regional basin floor fan system.
The Late Paleocene to Early Eocene (Wilcox equivalent) reservoirs are considered to be laterally extensive sheet sands that were deposited in deep water. These reservoirs are distributed across an area largely covered by the allochthonous Sigsbee salt canopy. It is this canopy that causes additional problems beyond merely the water depth and the well depth required to reach the reservoirs.
These exploration plays depend on understanding the updip fluvial/deltaic stratigraphic architecture and the potential for partitioning of reservoir-quality sandstones across the depositional shelf into the slope and basin floor environments. The Lower Tertiary is estimated to contain up to 15 billion bbl of oil.
Current State of Multizone TechnologyThe Generation IV multizone system has been deployed successfully in the Lower Tertiary by multiple operators. To the authors’ knowledge, the multistage completion system and enhanced single-trip multizone fracturing systems had been installed in 10 wells as of the summer of 2015, with additional well installations planned. These systems are rated to 10,000 psi, and the enhanced single-trip multizone tool system offering an open-hole variant was installed in one five-zone completion.
If it is a truism that the nations of the developing world are engaged in the process of developing, it is also clear that, for a variety of reasons, not all nations experience the process at the same rate. In the case of Angola—the populous southern African republic described in some quarters as a dynamic, emerging powerhouse, and in others as a would-be success story stymied by cronyism—the oil industry waits to see whether the effect of recent political shifts will change the economic and social course that the nation has charted in its often-tumultuous 42 years of independence.
The waters off the nation’s Atlantic coast hold enormous exploration and production potential, a fact that has allowed Angola to compete with heavyweight Nigeria as the continent’s top oil producer, even surpassing the Federal Republic for several months in late 2016. After years of working to impress upon the rest of the world that it was prepared to take on a major role in the continent’s future, Angola joined the Organization of the Petroleum-Exporting Countries (OPEC) in 2007. Its proven crude reserves stand at 9.5 billion barrels (at least 1–2 billion more barrels may also rest in its presalt blocks), with another 308 billion cubic meters of natural gas reserves. At its peak in early 2010, its crude oil production reached over 2 million B/D (as of June 2017, its production stood at 1.66 million B/D after the early-2017 OPEC effort to cut production, while crude oil exports reached 1.67 million B/D). Table 1 provides Angola’s oil production in recent years.
Angola is the second-largest African supplier of oil to China, and is a top-10 global producer of vented and flared natural gas. But Angola has, naturally, been subject to the same effects of low oil prices and market instability that have wrought recent havoc on all oil-based economies, especially in light of the fact that Angola’s production is highly dependent upon cost-intensive deepwater production. As the price crash settled into its deepest ebb in 2016, the influx of foreign money from its oil exports dropped a staggering 55%.
Its famously expensive capital Luanda continues to erupt into towering walls of glass and the cranes that hoist them, but skeptics believe that Angola’s growth may be too hollow and one-dimensional to project long-term economic growth. The question now is whether a recent change in leadership, in which longtime President José Eduardo dos Santos stepped down after legislative elections, means a genuine onset of economic diversification and social development for the nation’s 28 million people, and what such a transformation might mean for the industry in Africa.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 183383, “Integrated Off-Bottom Cemented Inflow-Control-Device System Design Toward Well-Delivery Optimization,” by Mohammed A. Al Madan and Mazen Bu Khamseen, Saudi Aramco, and Hedy Suherdiana and Ahmad Al Abdulmohsen, Baker Hughes, a GE company, prepared for the 2016 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 7–10 November. The paper has not been peer reviewed.
Off-bottom-cementing (OBC) operations are unique to Saudi Arabia and represent a very challenging approach to drilling and workover operations when deployed in combination with inflow-control devices (ICDs) across horizontal sections. The multitasking-valve (MTV) feature in upgraded ICDs offers safe, simple, and cost-effective deployment operations. This paper discusses the first deployment of an ICD system combined with an OBC system for a workover operation in a mature producer well in the Kingdom of Saudi Arabia.
In wells where an OBC liner is required to cover nontargeted formations above the production zone, two methods of deployment can be used: the one-trip system and the two-trip system. These refer, respectively, to whether the OBC components are deployed in a single trip along with the ICD or in a second trip with string in the previously deployed ICD completion. The one-trip OBC ICD completion does not allow an inner-string application. Therefore, circulation while running in hole was ineffective in this producer, which caused deployment problems.
The two-trip OBC ICD completion was then considered. The idea was to split the completion into a lower ICD completion, which is dropped off inside the openhole horizontal section with a setting sleeve. The earlier two-trip OBC ICD completion used an inner string, a circulating system, and an openhole-packer-setting tool. This allowed 100% circulation from the shoe during deployment of the lower ICD completion, although circulation rate is limited because of pumping through the small internal diameter (ID).
The upgraded ICD with an MTV allows the lower completion to be deployed without an inner string while achieving 100% circulation at the shoe, which smooths operations and saves up to 24 hours of rig time. The MTV temporarily blocks the communication between string and annulus while running in hole. Once reaching the setting depth, MTVs are actuated by hydraulic pressure. All hydraulically set equipment can also be set at this point.
Ultimately, in the case outlined in the complete paper, it was decided to combine once again the separated deployment into a single system by use of the MTV feature, which provides important functions for the one-trip OBC ICD completion—the ability to perform 100% circulation from the shoe and to set all hydraulic downhole tools with one setting ball.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 185499, “Fracturing-to-Production Integrated Completion Sensitivities for Horizontal-Well Design in the Vaca Muerta Shale,” by S. Pichon, F. Cafardi, G.D. Cavazzoli, A. Diaz, and M.R. Lederhos, Schlumberger, prepared for the 2017 SPE Latin America and Caribbean Petroleum Engineering Conference, Buenos Aires, 17–19 May. The paper has not been peer reviewed.
The boom in organic shale plays has revealed the critical need to size hydraulic-fracture treatments correctly to achieve commercial success. The right balance must be found between the cost of fracturing and the additional production achieved by increasing the formation-to-wellbore contact area. The complete paper examines a range of completion scenarios to evaluate the relationship between hydraulic-fracture design, production, and well profitability by use of numerical simulations to guide completion of horizontal wells in Argentina’s Vaca Muerta Shale.
The Vaca Muerta Shale is the source rock of most of the producing formations in the Neuquén Basin, with high potential as a standalone reservoir. The first well aiming at testing production from the play was drilled and completed in 2010, and, at the end of 2016, the production from the formation involved more than 600 wells. Well-construction practices have moved from creating vertical wells to creating horizontal wells.
In any organic shale play, completion has a significant weight in the total well cost and must be sized adequately. Completion design is composed of the volume and number of hydraulic fractures to be created along the lateral, and it must be engineered according to the specific features of each formation.
One of the principal features of an organic shale reservoir is the absence of commercial production unless the well is hydraulically fractured. Enhancing the contact area between the formation and the wellbore with hydraulic fractures compensates for the extremely low permeability of these formations. Multiple factors, including geomechanics and stress direction, drive the geometry of the hydraulic fractures. However, it must be noted that most organic shale reservoirs are overpressured. This factor tends to drive the stresses up and reduce their horizontal anisotropy.
Besides the hydraulic-fracture geometry, production is also the result of the hydrocarbon volume in place and the interaction of the flow capacities between the reservoir and the created network of conductive fractures. Therefore, the size of this surface of exchange created by the hydraulic fractures has a critical effect on the level and dynamics of the production profile.
Finally, economics is the balance between total well cost and production. The completion design affects both production and total well cost, making it a critical parameter.
Fracturing-to-Production Integrated Work Flow
Work-Flow Requirements. With the primary objective being the combined evaluation of completion design, hydraulic-fracture geometry, production, and economics, the methodology must allow an explicit description, at either the input or output level, of each one of the aforementioned parameters. The fracturing-to-production work flow fits this purpose and is proposed for this study. The work flow has been implemented successfully in the Vaca Muerta and various other shale plays.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 183413, “A to Z for Gas Tracers: A Decade of Learning and Experience,” by M.N. Khan, H. Iwama, A. Al-Neaimi, and O. Al-Shehhi, Abu Dhabi Marine Operating Company, and M. Chatterjee, Tracerco, prepared for the 2016 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 7–10 November. The paper has not been peer reviewed.
In interwell tracer studies, reservoir complexities often make tracer-breakthrough time difficult to assess. Although reservoir-simulation studies serve as an effective tool in predicting a breakthrough, the tracer behavior in the real porous media sometimes presents intriguing surprises. This paper discusses a crestal gas-injection project that was carried out in a supergiant heterogeneous-carbonate oil field.
A tracer-survey study can provide a variety of information about the heterogeneity of a formation. While transient tests can provide information about reservoir continuity, thief zones are difficult, if not impossible, to detect. This is because pressure-transient tests provide an arithmetic average for reservoir total transmissibility over the tested formation thickness, while a tracer survey provides a direct evaluation of the flow field between the injection and production wells.
Apart from heterogeneity, tracer studies also serve as an informative tool to yield fluid-flow paths inside the reservoir, popularly known as reservoir streamlines. A tracer survey not only can precisely identify these preferential paths that are detrimental to the sweep of the reservoir in the enhanced-oil-recovery stage but also can provide information about the time that fluid takes to move from one point (injection well) to another point in the reservoir. This time is termed the mean residence time. In addition, any flow barrier or directional thief zones such as faults can be identified by delayed tracer recovery. The mass-balance technique can be used to calculate the amount of tracer recovered to distinguish between the existence of a fault, a flow barrier, or a low-permeability zone.
Interwell tracer testing consists of injecting chemical tracers into injection wells at the beginning of a flood project or after the reservoir has reached its fill-up condition, depending on the objective of the project, and subsequent sampling of production wells for a prescribed period of time, which also depends on the objective of the project. Samples are analyzed for tracer content, which will delineate communication between the injection and production wells. The time during which samples are collected and analyzed depends greatly on the objective of the project. If the objective is to identify thief zones, deduce mean residence time, and determine other factors that could lead to full-field reservoir characterization that could be fed directly into a simulation model, sample collection and analysis must continue for a considerable period of time after tracer is first detected in order to establish a more-defined elution curve.