This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 185889, “The Nature of Drilling-Fluid Invasion, Cleanup, and Retention During Reservoir-Formation Drilling and Completion,” by Justin Green, Ian Patey, and Leigh Wright, Corex; Luca Carazza, Aker BP; and Arild Saasen, University of Stavanger, prepared for the 2017 SPE Bergen One Day Seminar, Bergen, Norway, 5 April. The paper has not been peer reviewed.
A reservoir-conditions coreflood study was undertaken to assist with design of drilling and completion fluids for a Norwegian field. Multiple fluids were tested, and the lowest permeability alterations did not correlate with the lowest drilling-fluid-filtrate-loss volumes. This paper will examine the factors that contributed to alterations in the core samples.
A range of measurements are made during reservoir-condition studies, with typical metrics of the performance of a fluid or sequence including the following:
These metrics are unfortunately subject to a number of factors that make interpretation difficult and therefore add risks to the decision-making process. In order to reduce these risks, a number of interpretive techniques are used. These include scanning electron microscopy (SEM), thin sections, and computed-tomography (CT) scanning.
In order to overcome some of the limitations posed by existing techniques, a micro-CT change-mapping technique was developed to show the distribution of alterations within samples at selected points in a study.
Do Filtrate Loss Volumes Tell Us How a Drilling Fluid Is Performing?
In terms of aiding operational decisions, the remaining mudcake attachment after a period of production or injection is most relevant in maximizing hydrocarbon recovery. The cleanup of drilling mudcakes will be influenced by a range of factors. An approach that allows a holistic view of the changes related to drilling fluid, taking into account as many relevant factors as possible, is therefore desirable.
Coreflooding is one of the principal tools through which we qualify drilling and completion fluids and assess the potential for formation damage, but is it relevant? By “relevant,” I mean does it give an accurate portrayal of the likely performance of the selected fluids in terms of potential damage and how effectively a well will clean up? These are important considerations, but can they be derived from a core plug that is representative of the main production interval and is used in a coreflood test where one of the main results obtained is a return permeability (the difference between the initial and final permeability after fluid exposure)? In reality, most use of coreflooding is in the selection of the optimal drilling and completion fluids on the basis of comparison of the return permeabilities. Many coreflood procedures use, for example, a standard sequence of drawdowns after exposure of the plug to drilling and completion fluids to represent cleanup without considering actual well conditions and expected flow rates. Are such core-floods relevant, or could we be discarding fluids that could function quite well if field-relevant coreflood testing conditions had been selected?
Are there instances where performing coreflooding is not relevant? Can the same mud formulation that has been tested and qualified for one field be used on an adjacent field where the reservoir type and conditions are similar? A thorough evaluation needs to be performed before making any decision, and there can be cases where additional coreflooding could be deemed unnecessary. How about the case where there has been a change to a mud formulation that has already been qualified by coreflooding (e.g., base oil has been changed with another or change to the emulsifier package)? Should the new formulation be requalified through coreflooding?
There are many questions here to think over; however, consider the first question: “Is coreflooding relevant?” Yes, it is. We will be discussing this topic along with others at the Friday Forum of the SPE International Conference and Exhibition on Formation Damage Control, 7–9 February, in Lafayette, Louisiana. Come along!
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 178963 Laboratory Simulation and Damage in Openhole Water Injectors by Michael Byrne, LR Senergy, et al.
SPE 183888 Best Practices for Effective Wellbore Cleanup and Displacements in Openhole Sand-Control Completions by M. Beldongar, Schlumberger, et al.
SPE 182320 Modeling of Slow Fines Migration and Formation Damage During Rate Alteration by Y. Yang, University of Adelaide, et al.
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 27663, “Stones Development: Turritella FPSO—Design and Fabrication of the World’s Deepest Producing Unit,” by Blake Moore, Andrew Easton, Jonathan Cabrera, and Carl Webb, Shell International Exploration and Production, and Babu George, SBM Offshore, prepared for the 2017 Offshore Technology Conference, Houston, 1–4 May. The paper has not been peer reviewed. Copyright 2017 Offshore Technology Conference. Reproduced by permission.
The Stones Project is in the emerging Lower Tertiary trend in the Gulf of Mexico ultradeep water. A floating production, storage, and offloading (FPSO) unit was selected for the floating production system to address the stepwise development of the Stones Field. The Turritella FPSO (Fig. 1) is the deepest floating production system in the world and presented many challenges to successful execution of the surface host facilities.
The Stones development is along the Walker Ridge protraction area in the deepwater Gulf of Mexico, in water depths ranging from 7,500 to 9,500 ft. The field was developed using a disconnectable FPSO tied to a subsea development. Nominal production capacities will be 60,000 B/D of fluids, 30,000 B/D of produced water, and 15 MMscf/D of associated gas. The FPSO design was based on the conversion of an existing Suezmax-scale, double-hull tanker.
Key design decisions during front-end engineering and design (FEED) and pre-FEED in 2012 and 2011 established many of the key design criteria that guided the design of the FPSO.
When considering the most significant aspects of new drilling technology to highlight for SPE readers, the latest downhole tools, rig design, and operational procedures often make the headlines. This year, however, a case can be made that the most profound advancements exceed anything achievable with new tools, procedures, or machines.
On 29 November, the San Antonio Business Journal reported a major oil company had sold a nearby data center to a West Coast cloud-computing giant in a deal estimated at $100 million. The next day, the companies executed a strategic contract to partner and further implement digitization of upstream assets in a cloud-computing environment. The oil company executive involved said, “We have started digitizing our oil fields but want to accelerate deployment of new technologies that position us to increase revenues, lower costs, and improve safety and reliability of our operations.” Far from an isolated event, this case is but one example of an overall trend revolutionizing our industry. Perhaps this is the dominant technology evolution transforming our landscape today.
Because drilling and well construction typically involve the majority of the cost and risk for upstream projects, this new revolution is inevitably the game changer for overall health, safety, and environment; efficiency; and financial performance on wells. Phrases such as “dawn of the new age of the oil and gas industry” and “the fourth industrial revolution” echoed through halls of SPE events in 2017 and into the new year, with rapid advancements in big-data management, digital connectivity, and high-performance computing (paper OTC 27638). Exciting developments in new downhole tools, fluids, and rig design continue to advance, with gains in safety and efficiency being multiplied by this transformation. The new revolution is also occurring in parallel with accelerated applications of managed-pressure- and underbalanced-drilling technology. The authors of highlighted paper SPE 185283 suggest the benefits of the technique collectively categorized as closed-loop drilling and the new drilling convention are so numerous that, indeed, all future rig operations should be configured as such. Concurrent with these trends toward increased data acquisition, data analysis, and remote control, automation of rig functionality continues as a primary focus and area of great potential across operator, rig-contractor, and equipment-supplier boundaries.
The 3-year industry downturn persisting through 2017 brought an unprecedented purging of paradigms. But perhaps the extreme pressure to reduce costs and add value has indeed forced the innovation and acceleration being realized today during this new revolution.
Recommended additional reading at OnePetro: www.onepetro.org.
OTC 27638 The Dawn of the New Age of the Industrial Internet and How It Can Radically Transform the Offshore Oil and Gas Industry by Partha Sharma, DNV GL, et al.
SPE/IADC 184695 Development to Delivery—A Collaborative Approach to Implementing Drilling Automation by Riaz Israel, BP, et al.
SPE 187477 Latest Drilling Techniques Applied to Coring Operations of a Complex Subsurface Geology in WCSB Led to Operational Success and Cost Savings While Setting a Record in North America by Ali Hooshmandkoochi, Seven Generations Energy, et al.
SPE/IADC 184650 The Floating Factory Concept: Engineering Efficiencies Up Front To Reduce Deepwater-Well-Delivery Cost by James Hebert, Diamond Offshore
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 18914, “Extracting More From Wireline Formation Testing: Better Permeability Estimation,” by S.R. Ramaswami, P.W. Cornelisse, SPE, H. Elshahawi, M. Hows, and C.L. Dong, SPE, Shell, prepared for the 2016 International Petroleum Technology Conference, Bangkok, Thailand, 14–16 November. The paper has not been peer reviewed. Copyright 2017 International Petroleum Technology Conference. Reproduced by permission.
The use of pressure-transient data in formation testing to describe reservoirs is considered mature technology, particularly when applied to data collected through production testing. The extension of this technique to data obtained using wireline formation testers (WFTs) has been gaining momentum in the industry; however, the integration of these outputs with other measurements of data is not always straightforward. The complete paper presents different methods of using pressure-transient data from WFTs; many of these methods are summarized here.
Pressure-Transient Data From WFTs
Perhaps the most widely used form of WFT pressure-transient data is that derived from small-volume drawdowns and buildups during a pressure test. The volume of fluid withdrawn from the formation, and the resulting depth of the pressure pulse, is limited to the near-wellbore region. The flow regime that develops during these tests is typically spherical flow in an infinite medium; hence, the mobilities derived from these sorts of pressure-transient tests are spherical mobilities and need to be converted to radial mobilities to quantitatively compare the tests. Additionally, pretest-derived mobilities have two fundamental challenges: the unknown effect of skin caused by drilling damage and the uncertainty of fluid viscosity to be used to convert the resulting mobility to permeability.
The other common application of pressure-transient information during wireline-formation tests uses pressure data over a much longer interval. During an extended pumping station with a WFT, a particular flow-rate history is applied to a well and the resulting pressure changes are recorded. From the measured pressure response, and from predictions of how reservoir properties influence that response, an insight into the reservoir can be gained. In order to make these predictions, it is necessary to develop mathematical models of the physical behavior taking place in the reservoir. Fig. 1 shows the difference between the volume investigated with a small-volume pressure test and an extended pumpout station. The most-common well model that is used when interpreting WFT data is the vertical limited entry model.
Fluid flow in porous media is governed by the diffusivity equation. To derive it in its simplest form, the following assumptions and simplifications have to be made:
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 179119, “A Well-Performance Study of Eagle Ford Gas Shale Wells Integrating Empirical Time/Rate and Analytical Time/Rate/Pressure Analysis,” by A.S. Davis and T.A. Blasingame, Texas A&M University, prepared for the 2016 SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, USA, 9–11 February. The paper has not been peer reviewed.
The purpose of the complete paper is to create a performance-based reservoir characterization by use of production data (measured rates and pressures) from a selected gas-condensate region within the Eagle Ford Shale. The authors use modern time/rate (decline-curve) analysis and time/rate/pressure (model-based) analysis methods to analyze, interpret, and diagnose gas-condensate well-production data. Reservoir and completion properties are estimated; these results are then correlated with known completion variables. The time/rate and time/rate/pressure analyses are used to forecast future production and to estimate ultimate recovery.
Production-Analysis Work Flow
The data required for the completion of the proposed methodology include well-history files, daily-rate and flowing-pressure measurements, and laboratory pressure/volume/temperature (PVT) and fluid-analysis reports. The following diagnostic plots are used to identify potential errors or abnormalities in the production data:
In addition to checking the integrity and correlation of production data, the authors also use the following diagnostic plots to establish the reservoir model and flow regimes:
Note that, for the diagnostic plots, an incorrect estimate of the initial reservoir pressure will yield plots that show skewed trends or clumping or scattering of data points, particularly at early production times.
On the basis of the information gathered from the diagnostic plots and well-history files, nonrepresentative production data points that are likely the result of nonreservoir effects or operational changes such as well-cleanup effects, liquid loading, well recompletions, well workovers, or choke changes are filtered. The diagnostic plots are prepared with the filtered production data to identify the flow regimes experienced by a given well. It is of primary importance to recognize if the well is still in transient flow or has already entered boundary- dominated flow because it allows determination of which of the time/rate relation models is appropriate for the given production data.
Argentina’s Vaca Muerta shale play is considered one of the most promising unconventional resources in the world. Advertised for years as the next great shale resource outside of the US, foreign investment has now picked up and the play may finally begin living up to its potential.
A comprehensive article beginning on page 26 outlines the current state of the Vaca Muerta, including geological and business challenges, as well as future development plans. Total output from Vaca Muerta in barrels of oil equivalent (BOE) has risen 60% since the start of 2016. Production is currently just over 75,000 BOE/D—split roughly evenly between oil and gas—but most of the money spent in the play so far has been in exploration; output is expected to rise sharply over the next decade.
Most of the current output comes from the Loma Campana joint venture between YPF and Chevron, but other projects may ramp up soon. Production is expected to rise to 113,000 BOE/D by the end of this year, and as high as 1 million BOE/D within 15 years, according to consultancy Wood Mackenzie. The shale rock in Vaca Muerta is considered very high quality, on a par with several US shale plays such as Eagle Ford, Bakken, and Marcellus.
Government-led reforms have been a major factor in its growth, in part because the country needs the economic benefits of Vaca Muerta. Once an energy exporter with a sound economy, Argentina last decade defaulted on $82 billion of foreign debt—the largest such default in history at the time. Elected president in 2015, Mauricio Macri vowed to put Argentina on sounder financial footing, and has his eye on replicating the shale boom in the US. After October’s elections consolidated his political power, he has embarked on a campaign to get international oil companies and domestic ones to up their investments in the shale play.
More than 15 companies are currently exploring in the Vaca Muerta, including big names such as Chevron, ExxonMobil, Total, and Shell. YPF and the government are also working to lower labor costs. Trade unions made concessions on contracts in exchange for commitments on spending, which the government said could cut development costs by 20%. YPF has announced a $30-billion, 5-year investment plan for Vaca Muerta, and ExxonMobil has committed $200 million to a pilot project there.
Before the country’s historic default, Argentina was a net exporter of oil and gas but lack of investment has turned it into an energy importer. Argentina’s oil production hit 489,000 B/D last year, down sharply from a peak of 847,000 B/D in the late 1990s. Gas output peaked at 4.5 Bcf/D in 2005 and is now roughly 3.7 Bcf/D.
The US Energy Information Administration estimates that Argentina has the world’s second-largest shale gas and fourth-largest oil resources. If the current momentum continues, Vaca Muerta may become the only viable shale play outside of North America.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 180181, “Catalog of Well-Test Responses in a Fluvial Reservoir System,” by J.L. Walsh and A.C. Gringarten, Imperial College London, prepared for the 2016 SPE Europec featured at the 78th EAGE Conference and Exhibition, Vienna, Austria, 30 May–2 June. The paper has not been peer reviewed.
Well-test analysis in fluvial reservoirs remains a challenge because of the depositional environment conducive to significant internal heterogeneity. Analytical models used in conventional analysis are limited to simplified channel geometries and, therefore, fail to capture key parameters such as sand-body dimensions, orientations, and connectivity, which can affect control-fluid flow and pressure behavior. The complete paper aims at a better understanding of the effect of channel content in complex fluvial channel systems on well-test-derivative responses.
Geological Modeling. 3D geological models with a centrally located well were generated and populated with varying fluvial geologies. A 6950-m×6950-m×300-ft geological model was set up that allowed the averaging effects of the heterogeneities and the reservoir boundaries to be visible on the derivative at late times.
Modeling the geology of a fluvial system is challenging because of changes in channel amplitude, amalgamation, and other processes through geological times, which yield highly variable distribution and shapes of fluvial deposits. Field X was modeled as isolated elliptical sand bodies and channel bodies, with sand-body dimensions of 105 m (width)×420 m (length)×5 ft (thickness) for the base case. The sand and channel bodies are schematically represented in Figs. 1 and 2. Object-oriented modeling was used instead of stochastic, sequential indicator simulation and Gaussian simulation to retain control over the modeling parameters.
Numerical Simulation. The corresponding pressure and derivative dynamic responses were generated using a proprietary finite-element simulator with a uniform grid and a fine local grid refinement (LGR) around the wellbore. The fluid was black oil at a reservoir pressure greater than the saturation pressure, and the relative permeability to water was low enough to limit water movement within the model.
Results and Discussion of Base-Case Model
A drawdown of 115 years was simulated for a geological model 6950 m×6950 m×300 ft with a cell size of 50 m×50 m×5 ft in the x, y, and z directions, respectively (total cell count without LGR=1,159,260), with a fine Cartesian LGR around the wellbore to reduce numerical artifacts around the wellbore (total cell count with LGR=1,327,200). The model consists of two facies. All simulations were performed without including wellbore dynamics or mechanical skin.
Vaca Muerta Rising: Building Unconventional Production From the Ground Up in Argentina
What is unconventional exploration and production in Spanish? YPF goes with “no convencional.”
The translation, not conventional, is a literal description for the sort of ultra-tight reservoir rock in the Vaca Muerta, the huge formation that the Argentine oil company says can return the country to the ranks of energy-exporting nations.
Not conventional is also the essential mindset required to do something nobody else in the world has accomplished: develop a massive shale play outside the US and Canada.
The potential is there. The US Energy Information Administration ranks Argentina second in the world among unconventional formations for technically recoverable gas and fourth for oil.
When YPF announced the discovery of a world-class shale play in 2011, it marked the start of years of work to solve a multidimensional puzzle presenting daunting geological, business, and political problems that has stymied the global spread of unconventional development. In the 6 years since then, YPF has shown it is possible to make money drilling and completing wells when oil prices are around $50/bbl while developing a block with Chevron.
Vaca Muerta Rising: Faster and Cheaper Without Losing Better
After Gustavo Astie, executive manager for unconventionals at YPF, presented what he thought was an aggressive growth plan for the coming year to YPF management, he was asked: Would it be possible to go faster?
The answer was, there are limits. In the past 6 years, YPF has built a foundation for profitably developing the Vaca Muerta, but it is just now beginning to see if what worked in the initial pilots can be transferred elsewhere in the huge formation.
When it comes to the pace of development, YPF needs to work with corporate partners providing much-needed money as well as expertise. Those partners include some of the biggest, most technically savvy companies in the industry, which took their time getting into unconventional development.
Vaca Muerta Rising: A Trip Along the Learning Curve
A drive down a gravel road in the Loma Campana follows the steep early learning curve in the Vaca Muerta.
There are large pump jacks on old single wells left from the early days when vertical wells were drilled on scattered sites in a place that looks a lot like West Texas.
There are pads with four vertical wells forming a rectangle. That pattern reduced the time needed to drill the wells by shortening the trip from well to well for older rigs not built to walk or slide on skids. Still it used two rigs, and the wells were far less productive than horizontal ones.
A flexible pipeline snakes along the edge of the road leading to a fracturing site where it supplies the fresh water needed for the job. Flexible water lines have become a common sight, replacing fleets of trucks pounding down the bumpy, unpaved roads.
Vaca Muerta Rising: Forces Favoring Shale Development are Aligned in Argentina, for Now
It is easy to fixate on what it will take to extract huge volumes of oil and gas from the nearly impermeable rock within the Vaca Muerta.
But in terms of the future of the huge Argentine unconventional formation, “the aboveground risk is far more important in the pace of development,” said Robert Lewis, a senior research analyst covering Latin America upstream for IHS Markit.
Scaling up this unconventional play will require spending billions of dollars a year and support from government policies that promote a stable investment climate, the ability to move money and goods in and out of the country, affordable deals with labor unions, and improved infrastructure.
Vaca Muerta Rising: Creating a Family-Friendly Oilfield Boomtown
Añelo is a small town in an arid, sparsely populated area with a new supermarket, police station, bank, skate park, hotel, and hospital.
In the past decade the population has roughly tripled to 7,000, and in 5 years, it is expected to nearly triple again to 20,000.
The catalyst for this boom is the development of the Vaca Muerta, an enormous unconventional oil formation that extends under the town.
As the town nearest to YPF’s office for this huge play, Añelo has recently attracted a cluster of service company offices, warehouses, and equipment yards on the edge of town. And more growth is expected as the national oil company scales up development.
For YPF, the goal is to turn the fast-growing town into a good place to live for workers and their families. But that is hardly a sure thing.
Your North America business is doing well. Will that continue to be your focus in the short term?
We are really excited about our business in North America. We have always had significant investment in North America and as we look at the immediate future, it will be the busiest market. It is extremely impactful on many different stages.
Do you see a slowdown in the unconventional business in North America, or do you think it is still on the way up?
I think that North America is going to be very resilient in a $50–55/bbl world. There is a lot of demand for North America resources and I think the speed to market is really relevant and important, particularly as demand increases. Unconventionals can fill that demand most quickly because of the timing more than anything else, which is a real advantage relative to mature fields and particularly deep water.
There is a lot of demand for what we do and I expect that we will be very busy in 2018. The sense I get from the customers is that the outlook is good at current commodity prices. We continue to reduce costs and make more barrels. And that’s how Halliburton spends most of its time—determining how to deliver the lowest cost per BOE.
Any fear that equipment shortages or labor shortages could slow activity?
I don’t think they will. The market is undersupplied today. We estimate that the market is about a million-and-a-half horsepower undersupplied for pumping equipment and I think the other services are also quite tight. Layer onto that the challenges with people and the shortages actually generate a flight to quality. One of the reasons I am confident about our business is that we have been disciplined about maintenance of our equipment and hiring people well ahead of time. That comes at a cost but the fact is there is no substitute for service quality. No substitute.
Outside of North America, where are the highest priorities for Halliburton?
We have outperformed the market through the downturn internationally in seven of the past eight quarters. The Middle East is extremely important to us. One of the things I am most pleased with is the ability of Halliburton to focus intently on North America, but at the same time steadily grow our international footprint. The fact is, we are present in every important market around the world today. That is something we could not have said 10 years ago and maybe even 5 years ago.