This article, written by Special Publications Editor Adam Wilson, contains highlights of paper IADC/SPE 178810, “Bridging the Gap Between MPD and Well Control,” by Thiago Pinheiro da Silva, Landon Hollman, SPE, Gustavo Puerto Corredor, and Patrick Brand, SPE, Blade Energy Partners, prepared for the 2016 IADC/SPE Drilling Conference and Exhibition, Fort Worth, Texas, USA, 1–3 March. The paper has not been peer reviewed.
Managed-pressure drilling (MPD) challenges the conventional drilling paradigm, along with drilling-contractor and operator policies and standards. Conventional drilling practices for connections, flow checks, tripping, and well control have been long understood and standardized both onshore and offshore. The addition of an MPD system to a drilling operation, inclusive of the recommended practices, requires bridging the gap between conventional policies and standards and those of MPD.
Often, an MPD bridging document that supplements the standard drilling-contractor and operator bridging document is seen as an operational requirement. The drilling contractor remains responsible for well control and well monitoring. The driller will continue to monitor the well at all times, using standard operating procedures while observing key drilling parameters.
The MPD system provides enhanced well-control-event-detection methods in addition to standard downhole-event-detection methods. In addition, it allows rapid and accurate control of bottomhole pressure (BHP), but it does not replace standard drilling-contractor or operator procedures during well-control events.
Depending on the MPD-system avail-ability and capabilities and the actual well conditions, most operators use several MPD techniques on the same well. The techniques may include conventional drilling with riser-gas-handling capabilities, dual-gradient dynamic-mud-cap drilling, pressurized-mud-cap drilling, floating-mud-cap drilling, or applied-surface-backpressure MPD. All of these fall into the group of techniques now referred to in the industry as MPD.
Depending on the technique used, the mud density might be statically overbalanced, meaning that the hydrostatic pressure alone exceeds the highest formation pore pressure exposed, or it might be statically underbalanced, meaning that hydrostatic pressure alone may be less than the highest formation pore pressure exposed and the well is kept overbalanced by applying backpressure at surface.
Well-established corporate policies have guided conventional drilling practices with respect to operational issues such as kick-indicator response, frequency of equipment testing, fingerprinting, and proactive kick-minimization techniques. Although MPD serves the same purpose as conventional drilling—to drill a section safely overbalanced—its use requires procedures that deviate from established policies.
Conventional Drilling. For conventional drilling techniques, a minimum of two independent and tested barriers must be in place at all times. Upon failure of a barrier, normal operations must cease and not resume until a two-barrier position has been restored.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 184716, “Successful Multiwell Deployment of a New Abandonment System for a Major Operator,” by Thore Andre Stokkeland and Jim McNicol, Archer Oiltools, and Gary McWilliam, Maersk Oil, prepared for the 2017 SPE/IADC Drilling Conference and Exhibition, The Hague, The Netherlands, 14–16 March. The paper has not been peer reviewed.
A new downhole-tool-based abandonment system was developed and deployed successfully on four wells for a major operator on a field in the North Sea. The operations were executed with each well taking less than 18.5 hours to secure. The successful operation saved the major operator considerable time and expense by eliminating the need for cutting and pulling the 10¾-in. casing to remove the oil-based mud (OBM) from the annulus before removing the wellheads.
Service companies were challenged by a major operator to create a solution to set a barrier against the overburden and to circulate OBM out of the annulus between the 10¾- and 13⅜-in. casings before pulling the wellhead.
The first stage of the operation was to run a perforation gun loaded for 1 ft with 18 shots/ft (spf) of a proprietary abandonment charge (single-casing perforation gun) to immediately below the wellhead at 475 ft. Then, the 10¾-in. casing was perforated with 0.8-in.-diameter holes without damaging the 13⅜-in. casing to create a circulation path.
The second stage was to run a retrievable bridge plug (RBP) with another 1-ft-long perforation gun below. The RBP was set and perforated immediately above the 13⅜-in. shoe at 2,300 ft; then, circulation was established up to the shallow perforations above and the OBM in the 10¾- by 13⅜-in. annulus was circulated out. After the circulation parameters were established, a wash pill was pumped around the annulus to clean out the OBM.
The third step was to set the actual overburden barrier in the A and B annuli. This was achieved by displacing cement through the ball valve of the RBP into the perforations below the RBP, placing the cement plug below and into the 10¾- by 13⅜-in. annulus. The ball valve was closed, and a cement plug was pumped on top of the RBP, completing the barrier.
The North Sea’s Leadon Field lies in 370 ft of water and is located in Blocks 9/14a and 9/14b of the UK Continental Shelf approximately 220 miles northeast of Aberdeen. Field development was enabled by the addition of two satellite fields, Birse and Glassel. The three fields were developed with subsea horizontal wells tied back to a floating production, storage, and offloading facility. The Lark and Horda formations produce in two well clusters, A and B. Cluster A has seven production wells and two water injectors; Cluster B consists of three production wells, two water injectors, and two aquifer wells. Both clusters have space for additional wells.
After a commercially successful period, production eventually declined, leading to a Cessation of Production Application being filed by the operator in 2004. A decommissioning program for the field was approved in March 2016.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 187369, “A New Three-Phase Microemulsion Relative Permeability Model for Chemical-Flooding Reservoir Simulators,” by Hamid R. Lashgari, Gary A. Pope, Mohsen Tagavifar, Haishan Luo, and Kamy Sepehrnoori, The University of Texas at Austin, and Zhitao Li and Mojdeh Delshad, Ultimate EOR Services, prepared for the 2017 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 8–11 October. The paper has not been peer reviewed.
The complete paper presents a new three-phase relative permeability model for use in chemical-flooding simulators. A model that has been widely used in chemical-flooding simulators for decades has numerical discontinuities that are not physical in nature and that can lead to oscillations in the numerical simulations. The proposed model is simpler, has fewer parameters, and requires fewer experimental data to determine the relative permeability parameters compared with the original model.
Two- and three-phase relative permeability measurements at low interfacial tension (IFT) have been published previously, and microemulsion relative permeability models have been proposed in the literature as well. But none of these can model the microemulsion phase across different phase-behavior environments, from oil-in-water, to the middle phase, to water-in-oil emulsions. Desirable features should include agreement between two- and three-phase micro emulsion relative permeability and oil-recovery data, and relative simplicity for use in reservoir simulators with a minimum number of model parameters that can be estimated from experimental data in a straightforward way. Satisfying these requirements has turned out to be an extremely challenging task.
The objective of this study was to develop a simple, continuous two- and three-phase microemulsion relative permeability model with relatively few parameters that is practical for use in chemical-flooding simulators. Discontinuities in relative permeability cause numerical problems that can cause severe reductions in the size of the timesteps. Discontinuities also cause errors in the physical predictions of important phenomena such as phase trapping and surfactant retention. The need for a continuous model has been well-known, but it was a challenging task to develop a continuous model because of the complexity of three-phase microemulsion phase behavior.
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 187345, “A Novel Approach To Rejuvenate a Brownfield by Validating Dynamic-Model Response With Near-Wellbore-Saturation Monitoring,” by Shubham Mishra, SPE, Karthik Kumar Natarajan, SPE, Akshay Aggarwal, SPE, Aditya Ojha, SPE, Alexander Rincon, SPE, Isha Khambra, SPE, Ajit Kumar, SPE, and Gaurav Agrawal, SPE, Schlumberger, and Pankaj Kakoty, SPE, Neelimoy Baruah, and Sanjay Kumar Dhiraj, SPE, Oil India Limited, prepared for the 2017 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 9–11 October. The paper has not been peer reviewed.
Fields in the Upper Assam-Arakan Basin have been studied intensely to find prospective sweet spots, perforation intervals for new wells, and potential workover candidates. These forecasts, guided only by dynamic-numerical-model results, have had mixed results when implemented in the field. A validation of the dynamic-model forecasts with near-wellbore-saturation logs can help reduce uncertainty. The validation was carried out in old wells, which helped in making informed decisions about tapping bypassed hydrocarbon pockets.
An integrated seismic-to-simulation study was conducted on 42 reservoirs in 375 km2 of the Upper Assam Basin. As a result of this study, the overall structural framework, well correlations, and fault mapping have been revised considerably compared with previous interpretations. Previously, the only data available to manage these fields were from paper-based 2D maps, from which some volumes were estimated by use of simplistic techniques. Now, the numerical-model-based approach can provide a better understanding of stock-tank oil initially in place and leftover pockets of oil. A phased field-development plan (FDP) for the next 5–10 years was proposed from this study.
After completion of the FDP study, executing the recommendations in a timely manner was essential and the dynamic model was updated with the production results accordingly. Therefore, a work flow was created to increase the effectiveness of workover activities by incorporating validation with near-wellbore-saturation-log readings.
Using the dynamic model, the following eight factors were considered for each candidate well before a workover was recommended:
A method was implemented to validate the near-wellbore hydrocarbon saturations predicted in the history-matched dynamic model though integration of FDP results with pulsed-neutron-tool-log interpretations for the recommended workover candidates. Perforations were then proposed for the validated intervals. The study also aimed to eliminate preplanned workovers that were not predicted as prospective by the FDP after confirmation with near-wellbore- saturation logs.
Cyberattacks are an increasing threat to businesses and organizations globally, and the oil and gas industry is and will remain a prominent target.
At the American Petroleum Institute (API) annual Cybersecurity Conference held recently in Houston, James Morrison, a technical expert on information technology (IT) with the United States Federal Bureau of Investigation, told an industry audience, “Every single one of you will be attacked, if you have not already been attacked.”
During 2016, 75% of oil and gas companies had at least one cyberattack, he said, stressing that companies must do more to protect their data and “the industrial control systems behind that data.”
All facets of industry business, very much including operating activity of any kind, are exposed and will only be more so as the Internet of Things proliferates.
More Than a Digital Issue
Thus, cyberdefense is much more than a digital or IT issue. It carries implications for every dimension of business, including health, safety, environmental, and financial activity. Cybersecurity experts are adamant that operations technology (OT) systems cannot be viewed as safe simply because they are not IT systems. While they have differing characteristics, IT and OT systems must be viewed as a continuum.
More than 200 groups globally, including some linked to national governments, are believed to be involved in cyberattacks on US installations, and the number appears to be growing with the rise of criminal activity on the dark web, Morrison said. However, the number of attack groups is surely larger than those known to have targeted US installations.
If there was a consensus coming out of the API conference, it was that the industry is not doing enough to protect itself. While companies may have protective programs and processes in place, the companies generally approach the problem reactively. “We’re actually getting a little numb about too many attacks,” Morrison said.
Disrupt the Attackers
What companies mainly are failing to do is embrace measures that can disrupt the by now established business models of many cyberattackers.
Ransomware attacks, for example, are affecting businesses of all sizes and types and have been growing phenomenally, according to Michael Leigh, the global head of incident response at NCC Group, a cybersecurity and risk mitigation consultant. These attacks use a type of malware that prevents or limits users of a computer system from accessing it until a ransom is paid.
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper IADC/SPE 178835, “Differentiate Drilling-Fluid Thermal Expansion, Wellbore Ballooning, and Real Kick During Flow Check With an Innovative Combination of Transient Simulation and Pumps-Off Annular Pressure While Drilling,” by Zhaoguang Yuan, Dan Morrell, SPE, Aldrick Gracia Mayans, SPE, and Yahya H. Adariani, Schlumberger, and Matthew Bogan, Noble Energy, prepared for the 2016 IADC/SPE Drilling Conference and Exhibition, Fort Worth, Texas, USA, 1–3 March. The paper has not been peer reviewed.
Drilling-fluid thermal expansion, wellbore ballooning, and formation kick are similar in terms of surface observations such as pit volume gain. Each of these events, however, is solved in different ways. Treating wellbore ballooning the same way as a kick likely will result in losing the current borehole after days or weeks of unsuccessful operations. In this study, pressure-while-drilling technologies are combined with software simulations to differentiate drilling-fluid thermal expansion, wellbore ballooning, and formation influx during riserless drilling operations.
Thermal Expansion. Because mud density is dependent on temperature and fluid compressibility, volume gains or losses because of thermal effects may be substantial, especially in high-pressure/high-temperature and deepwater wells. Thermal expansion typically results in small volume changes and low flow rates because it takes time for the mud to heat up after circulation stops. Depending on the downhole conditions, however, muds can heat up sufficiently to produce significant flowback for a short period of time.
Formation-Fluid Influx. If the mud-weight hydrostatic pressure is insufficient to contain formation influxes, when the pumps are shut down, the loss of the frictional pressure created during pumping can allow formation fluid to flow into the wellbore, assuming the formation fluid has sufficient mobility. This is described as a kick, or formation-fluid influx. It is verified by performing a flow check and observing mud returns at surface over time to determine a trend in pit gain. A steady increase or accelerating trend will be interpreted as a kick, although, in many cases, the well will be shut in before a clear trend can be established.
U-Tube Effect. In riserless drilling, two different fluid densities exist—in the annulus (mud and seawater) and in the drillstring (mud). Because fluids flow from a higher-pressure area to a lower-pressure area, a U-tube effect will occur once the pump stops. This will show as flow at the wellhead with a high flow rate initially, declining as the U-tube effect equalizes. The volume contribution from the U-tube effect is relatively simple to quantify, so, in the cases where surface volumes are measured, this effect will be somewhat easier to distinguish.
Wellbore Ballooning. Changes in equivalent circulating density (ECD) and hydrostatic pressure can result in wellbore ballooning, where the formation takes drilling fluid when pumping and the injected fluid then flows back into the well when the pumps are shut down.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 183321, “An Improved Approach for Estimation of Flow and Hysteresis Parameters Applicable to WAG Experiments,” by Pedram Mahzari and Mehran Sohrabi, Heriot-Watt University, prepared for the 2016 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 7–10 November. The paper has not been peer reviewed.
Water-alternating-gas (WAG) injection has demonstrated encouraging results for improving oil recovery. However, numerical simulation of three-phase flow and the associated hysteresis effects are not well-understood. In the complete paper, a new assessment of the WAG-hysteresis model, which was developed originally for water-wet conditions, was carried out by automatic history matching of two coreflood experiments in water-wet and mixed-wet conditions. The results indicate that history matching the entire WAG experiment would lead to a significantly improved simulation outcome.
Using an optimization software, the authors have carried out a series of history-matching exercises on coreflood experiments to evaluate the performance of the WAG-hysteresis model and to simulate WAG experiments conducted on mixed-wet and water-wet cores at near-miscible conditions. The main difference here compared with previous work is the tuning of the parameters relevant to the WAG-hysteresis model on entire WAG experiments (rather than on individual cycles of one experiment) with a new methodology to estimate more-representative two-phase relative permeability curves from the WAG experiments.
Coreflood Experiments and History-Matching Method
There are numerous coreflood experiments in the literature that can be used for studying pure WAG-related interactions at near-miscible conditions. The unique advantages of this data set are gravity-segregation effect has been excluded by rotating the core while the fluids were being injected and all the fluids (water/oil/gas) were thermodynamically pre-equilibrated to minimize the effect of mass transfers at near-miscible conditions. Therefore, the processes taking place in the coreflood experiments can be attributed solely to multiphase flow and hysteresis effects. The following coreflood tests were selected from the data set to investigate the behavior of flow functions with respect to fluid saturation, injection scenario, and initial wettability:
After years of low oil prices, the focus is on adding a lot of value for a little cost. SPE’s technical directors are talking about adding value to everything from a petroleum engineering degree to a wellbore.
A failure to do so can mean a degree that does not prepare a student to con-tribute after graduation, or a well whose production fades early.
Those working as petroleum engineers have a generation’s worth of challenges to address due to the push into unconventional development. Those results will determine how much value can be coaxed from these ultra-tight rocks.
For those designing projects that will get built, it pays to think small. A standardized, modular design can deliver value at a cost that is lower, and more likely to come in within the budget.
Doing more with less in drilling means there are fewer drilling rigs in the world, and the job of many engineers still working will be to identify the best available technology to continue to reduce the number of rigs required.
Leaders need to be aware of the value that can be destroyed by mistakes made by humans interacting with complex systems.
And SPE needs to identify and support successful efforts to address health, safety, and environmental challenges, to help spread good ideas and show the difficult challenges the industry can and does address. The value of those efforts is often hard to measure, but it can be big.
Ramona Graves, Academia
The value of a petroleum engineering degree varies widely, depending on where it was earned. In many universities in the developing world, where hiring local workers is essential, the petroleum engineering graduates are far from ready to begin contributing, said Ramona Graves, the director representing academia.
Jeff Moss, Drilling
Drilling engineers are looking ahead to more years of managing jarring change. Jeff Moss, technical director for drilling, said the rapid increase in drilling productivity in recent years is a prelude to more of the same as drilling engineers sift through a flood of digitally controlled offerings promising even greater efficiency.
Hisham Saadawi, Production and Facilities
It is not the time to be thinking big in oil and gas facilities. Hisham Saadawi, technical director for production and facilities, said the focus has shifted from megaprojects to smaller projects where the investment management challenges and risks are all lower. Often companies are “looking at existing facilities to maximize return on the investment made,” he said.
Tom Blasingame, Reservoir
Reservoir engineers have a lot of promises to fulfill. “We were promised big data would save us. That more simulation would save us. And we were promised that we could understand flow regimes at scales we have not been using for the past 100 years,” said Tom Blasingame, technical director for reservoir.
Jennifer Miskimins, Completions
A keyword for completion engineers is interactions. For Jennifer Miskimins, technical director for completions, those range from production-altering pressure surges from well to well during fracturing to collaborations with drillers and reservoir engineers to build more productive wells.
Johana Dunlop, Health, Safety, and Environment
Recognition of industry success is on the growing list of things to do for the new technical director for health, safety, and environment (HSE), Johana Dunlop.
J.C. Cunha, Management and Information
Offshore drilling involves “an amazing set of equipment and high technology … run by human beings.” That sort of human interaction with complex systems has been on the mind of J.C. Cunha, whose term as technical director for management and information ended this fall. He is thinking more needs to be done to “reduce human error in complex systems.”
The production growth in the Permian Basin has created a new dilemma for operators looking for cost efficiency. In September Bloomberg predicted that Permian production could rise from its present level of 2.4 million BOPD to 10 million BOPD, a rate that could produce up to 50 million B/D of flowback water. With the WTI price at around $57/bbl in early December, disposal of that flowback water can be expensive. Bloomberg estimated the cost of the service is between $1.50 to $2.50/bbl.
While this predicted spike in water volume may be an issue for operators, it is an opportunity for oilfield water management companies working in the region. With demand for their services going up, these companies have already begun acquiring pipeline infrastructure, saltwater disposal (SWD) wells, and facilities.
With water management becoming a critical issue for operators in the Permian, midstream companies have been aggressive with mergers and acquisitions in their efforts to bolster their positions. H2O Midstream’s acquisition of Encana’s produced-water-gathering system last June gave it control of more than 100 miles of interconnected pipeline and five SWD wells with a total permitted disposal capacity of 80,000 BWPD. In September 2017, RRIG Water Solutions announced the acquisition of a 475-mile pipeline from Oilfield Water Logistics. Located in the eastern part of the Delaware Basin, the pipeline has the potential to move more than 2.3 million B/D of fresh water.
WaterBridge Resources is another company that has been active in the Permian region. Since its founding in 2015, the midstream development company has focused on acquiring and operating flowback and produced water infrastructure for various oil and gas producers, including water sourcing, gathering, reuse, pipeline infrastructure, and disposal infrastructure.
In August 2017, WaterBridge acquired EnWater Solutions, a company whose current assets include more than 100 miles of gathering line and nearly 150,000 B/D of permitted disposal capacity. WaterBridge plans to extend EnWater’s existing gathering business into a full-cycle, closed-loop water sys-tem, and by the end of 2018 the company expects to have more than 300,000 B/D of disposal capacity and 200 miles of interconnected gathering pipe.
“The assets we acquired from EnWater are located in the southern Delaware, and the EnWater team’s expertise encompasses the entire Permian region from the Delaware to the Midland, so that was a regional platform with an existing management team that are certain areas across the US where the water/oil ratio is much greater. The Eagle Ford is fairly dry, the SCOOP/STACK is fairly wet, and the Permian’s fairly wet. The water/oil ratios are what we chase because, at the end of the day, our business is a volumetric business. The greater the volumes of water to be handled, the better our profitability is.”
Editor's columnIn this issue, SPE’s technical directors evaluate the current state of the upstream oil and gas industry and offer their outlook for what will drive the sector in 2018. After several years of low oil prices and heavy restructuring, it is no surprise that cost containment and adding value are at the top of the agenda, from drilling to completions.
Parts of the industry are still adjusting to change. Shifting demographics, increased automation and digitization, and the ever-increasing flow of data will continue to have an impact on the industry for the foreseeable future. In general, analysts who study the industry predict that 2018 will be a year of stability and continued gradual recovery: oil prices should hold steady or slightly rise, and OPEC and non-OPEC producers will chart their course forward as the supply overhang gradually subsides, leading to a market in better balance than it has been in 3-4 years. The big picture will focus on OPEC and other large producers’ adherence to production cuts, the continued rise in shale output in the US, and whether global demand can whittle away at the oil surplus.
Deloitte sums up the past year and how it will impact the new one in its 2018 Outlook On Oil and Gas. Among its observations is the surprise of the US coming into its own as an energy exporter. When the US oil export ban was lifted in January 2016, it was thought that it would have little effect on the global market. But the US has become a regular exporter of crude oil, especially unconventional, to as far away as Asia, as well as a force in liquefied natural gas and refined products. If the trend continues, the US will have gone from a heavy net oil importer to a truly global player in the market, especially as unconventional production continues to climb, in just a few years. That also has implications for national security and global geopolitics.
Deloitte points out that the question coming into 2017 was whether cost reductions in unconventional production would be sustainable. “The evidence seems to tell us they are, with break-even costs across the major US shale plays still 30-50% below the levels of early 2015,” its report says. The downside is that, although many producers are not only surviving but doing well, the oilfield services industry is still reeling “and further consolidation may be in the cards.”
OPEC’s extensions of cuts along with major producers such as Russia has been key to stabilizing prices. But with non-OPEC production climbing, the market still needs a significant demand boost to solidify prices. OPEC and the other producers first announced their cuts in late 2016, and the adherence to them has been stellar. The cuts were extended another 6 months and, in late November, another 9 months to the end of 2018. How long these producers, especially Russia, are willing to curtail output will have a major influence on oil prices in the coming year.