This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 191437, “ACA Practical Considerations: When Is It Accurate and How Should It Be Used To Improve Reservoir Stimulation,” by O.A. Ishteiwy, SPE, M. Jaboob, and G. Turk, BP; S. Dwi-Kurniadi, SPE, Schlumberger; A. Al-Shueili, SPE, A. Al-Manji, and P. Smith, BP, prepared for the 2018 SPE International Hydraulic Fracturing Technology Conference and Exhibition, Muscat, Oman, 16–18 October. The paper has not been peer reviewed.
The use of diagnostic fracture injection tests (DFITs) for prefracture investigation has become routine in the oil field, particularly for understanding reservoir properties and subsequently optimizing hydraulic-fracture design. A key component of an effective DFIT is an after-closure analysis (ACA) to assess the transmissibility of the formation and allow for effective design. This paper describes a DFIT-analysis program and the suitability of the results from ACAs for use in hydraulic-fracture design.
The Khazzan field is being developed currently and includes multiple gas-bearing formations. The primary development reservoir is the Barik sandstone, which is characterized by permeabilities on the order of 0.1 to 1 md. An additional reservoir under development is the Amin formation, which lies deeper than the Barik and is perhaps more unconventional in nature, with estimated permeabilities an order of magnitude lower than the Barik formation. Both reservoirs require hydraulic fracturing to produce at economically attractive rates and, as such, carry the same sort of challenges to reservoir understanding inherent to all unconventional plays. This was recognized in advance of the appraisal program, and an approach was taken to address these challenges in a more-holistic fashion, encompassing a full suite of data gathering, including surveillance and well testing.
One of the key tools used was DFIT along with associated ACA of the decline to determine reservoir properties. During the appraisal phase, significant rigor was aimed at ensuring high-quality data would be recorded and that an appropriate amount of time would be allocated to monitoring pressure declines to enable valid interpretations. This resulted in the ability to draw a good correlation between data gathered from the ACA operations and data collected from post-fracturing well-test data.
Methods and Process Stimulation and Testing Sequence. The approach taken to stimulate and test the wells in Khazzan was to use a dedicated well-test unit. The overall sequence was as follows:
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 190062, “A Pulsed-Neutron Comparison Between an Open- and Casedhole Well: An Alaskan Case Study,” by J. Burt, T. Zhou, D.A. Rose, R. Grover, S. Ahmad, and J. Nemec, Schlumberger, and J. Dunston, Hilcorp, prepared for the 2018 SPE Western Regional Meeting, Garden Grove, California, USA, 22–27 April. The paper has not been peer reviewed.
This paper compares the results of gas identification and lithology identification using pulsed-neutron spectroscopy in openhole and casedhole environments. Most pulsed-neutron tools are run after casing; this study provides a unique opportunity to examine the effect of casing on spectroscopy by comparing casedhole measurements to measurements taken in the open hole before the casing was run.
Pulsed-neutron logging has evolved over the last 50 years, but the intrinsic physical measurements have remained unchanged, which means that operators cannot obtain a complete picture of the rock and fluids behind casing with conventional tools. However, advances in tool design and a new fast-neutron cross-section (FNXS) measurement provide for an alternative gas-identification technique. Gas in open holes is typically identified from neutron porosity and gamma-gamma density crossover. In casedhole environments, gamma-gamma density measurements are challenging because of the large casing and cement corrections needed. Previous gas identification in casedhole environments has relied on the formation hydrogen index (HI) or neutron porosity (TPHI) log and sigma.
In openhole environments, density and neutron porosity crossover is a typical gas identifier, but, in many instances, shale can mask the identification of gas. This is a common problem in some gas reservoirs in Alaska, and it leads to ambiguous interpretations about the gas saturation and potential producibility of different zones. Gas identification in casedhole environments is even more complicated because the density measurement is not commonly available.
The FNXS measurement responds primarily to formation atom density, for which most rocks, clays, and liquids have similar values. Comparatively, gas has a low atom density, and its presence will make the FNXS measurement read low. Thus, a gas pay zone can be differentiated from tight zones by the shift toward lower FNXS values. Also, the difference in FNXS between clean lithologies and clay is less than for sigma and TPHI, so FNXS, which is less affected by variable clay content, can be a more-robust gas indicator when variable clay is present.
A few weeks ago, a very passionate discussion took place within the SPE reservoir online community about climate change and global warming. The issues were, not surprisingly, about the reality of global warming and about the role of human activity. This was certainly the most passionate debate this online community has had for the past few years, with a lot of people denying either the concept of global warming, or the role of an anthropogenic (i.e., man-induced) effect on greenhouse gas emissions.
As I am not a climate scientist, I did not join the discussion. However, I have learned a few things on this subject by reading a lot of literature:
For these reasons, it appears to me that climate change caused by an increasing greenhouse gas effect, mostly the result of carbon dioxide emissions, is likely, even if I have no absolute factual evidence for that. Most important is the fact that, globally, a growing and already important number of people, including the general public and decision makers, have the same opinion and related concerns. Also, this opinion is very widely shared within the younger generations. I had the opportunity as SPE president a few years ago to meet a large number of university students all around the world, and I have been very impressed to see the concern about climate change by the vast majority of these students. And the discussion in the SPE online community I mentioned earlier was joined mostly by experienced members and included few (if any) younger members. For those who want to persuade people and politicians that this is not an issue, it looks like the battle is already lost, and the policy of the current US administration cannot change long-term trends, although it may delay things a bit.
A consequence of all this is the development of “green” alternatives. I note that the meaning of “green” is unclear for many people: does it mean decreasing emissions of polluting agents, such as sulfur compounds, nitrogen oxides (NOx), fine particles, etc., all detrimental to human health? Or does it mean decreasing emission of greenhouse gases, mostly carbon dioxide? Or does it mean both?
My year as your SPE 2018 president
Wow. One hundred twenty-four speeches and counting, 39 countries visited, millions of excited volunteers (estimated from good feelings that I have had).
Life is grand. … My knees are really sore. There are bags under my eyes. What’s left of my hair is way grayer than when I started. I’ve busted two of my four accordions from travel stress, and I’m not sure if I have slept properly in about a year.
These are the thoughts that have run through my head as I have had the great honor, rather the great honor, of serving you as your SPE 2018 president. What a ride! I am so humbled.
As I prepare to pass the torch over to my eminently well qualified successor Sami Alnuaim, (a way smarter guy than me) I do so with an immensely thankful heart. I have learned so much. I have been surprised many times. I have been disappointed almost never. What a great bunch of members SPE is proud to call its own.
It is hard to describe the gravity and responsibility of leading this society. With almost 160,000 really great people—all contributing something unique, all are really smart and work really hard—it’s no wonder why we are an industry that is one of the most technical on the planet. There are a really smart bunch of folks working in it. From Kavala, Greece, to Adelaide, Australia, I have been constantly surprised with the wonderful people we call members. I am so unworthy to represent such a group. I only hope that I have chaired the board without prejudice and fostered the robust activities that we undertake.
People—we, the SPE—set the standard that defines the process that provides the majority of the world’s energy needs. We are the global experts who give the planet home heating, products such as plastic, energy to power our cars, and a myriad of life improvements.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 29069, “How AI and Robotics Can Support Marine Mining,” by Peter Kampman, Leif Christensen, Martin Fritsche, Christopher Gaudig, Hendrik Hanff, and Marc Hildrebrandt, German Research Center for Artificial Intelligence (DFKI), and Frank Kirchner, DFKI and University of Bremen, prepared for the 2018 Offshore Technology Conference, Houston, 30 April–4 May. The paper has not been peer reviewed. Copyright 2018 Offshore Technology Conference. Reproduced by permission.
Marine mining initiatives open a new field of subsea operations. Offshore oil and gas sites are still located primarily in areas where divers can support maintenance and repair requirements, but future marine mining will take place in greater depths and with a complexity of machines that requires support from robotic systems equipped with a substantial amount of artificial intelligence (AI). Technologies are being developed that have the potential to support marine mining in all stages from prospection to decommissioning. These developments will likely have substantial influence in the oil and gas industry, itself searching for ways to maximize exploitation of assets.
Under Current Development Increasing Autonomous Underwater Vehicle (AUV) Intelligence. Commercial off-the-shelf AUVs rely mostly on acoustic and inertial sensors for their navigation. Speed measurements from a Doppler velocity log are combined with orientation values from gyroscopes and accelerometers to estimate current position. These updates are sometimes augmented by absolute-position fixes from an ultrashort baseline system. However, during such a mission, the inspection assets might not be located exactly at their expected positions. This might be because of incorrect positioning during installation, objects being dragged off location by fishermen, or sediments hiding a pipeline gradually from the view of standard sensors. Therefore, equipping modern AUVs with sensors and software that can search for, detect, track, and re acquire inspection targets is essential.
In addition, classical sensor suites consisting of cameras and sonars can be augmented with higher-resolution 3D sensing such as laser-line projectors (structured light). This enables an AUV’s onboard software to create a millimeter-precision 3D model of the asset, which can be compared with computer-aided-design models or previous-inspection-run data. By using a fully automated 3D-model cross-check, the AUV could detect asset deformations, defects, or marine growth, even while still submerged during the inspection run.
Seafloor AUV Support Infrastructure. Current AUVs have limited endurance, mostly because of limited battery capacity. Depending on the sensor suite, on-board data-storage space also can be a limiting factor. This causes AUV missions to run no longer than a few days at most, depending on AUV size and shape, propulsion, sensor efficiency, and environmental conditions in the deployment area.
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 27987, “Subsea-Fiber Wet-Mate Connectors: Achieving the Balance Between Consistent Optical Performance, Product Cost, and Compact Size,” by Elaine Saxton and Helyson Parente, SPE, Siemens Subsea, prepared for the 2017 Offshore Technology Conference Brasil, Rio de Janeiro, 24–26 October. The paper has not been peer reviewed. Copyright 2017 Offshore Technology Conference. Reproduced by permission.
As the hunger for data grows, long stepouts become more common, and fiber communication becomes standard, the use of fiber in subsea oil and gas fields is set to increase. While optical loss along fiber itself is low and data-collection possibilities are high, these applications will only be fully realized if wet-mate fiber connectors can achieve high optical performance consistently. Excellent results are achieved with compact design, a modular approach, and an emphasis on cleanliness.
Wet-mate fiber connectors have been on the market for years and are used increasingly in the subsea oil and gas industry. While they have been moderately successful, the technical challenges should not be underestimated. Industry specifications demand high levels of optical performance and extensive qualification programs. The balance between performance and cost of the finished product has always been difficult to achieve.
Subsea fields are seeing longer stepouts, which are suited to using fiber as the key communication network. Furthermore, the subsea industry is seeing an ongoing drive to use fiber sensors in downhole systems (e.g., distributed temperature sensing), allowing greater amounts of data to be transmitted topside. Other applications such as direct-current and fiber-optic distribution and pipe-in-pipe heating are also emerging. For reasons of flexibility and practicality, the wet-mate fiber connector plays an important role in all of these.
The key technical challenges are a mixture of mechanical design, operation and maintenance, and operational environment.
Mechanical Design. The core of a standard single-mode fiber is 9 µm, and it must be completely aligned in every dimension for optical performance to be achieved.
Manufacturing, Operation, and Maintenance. Cleanliness of the optical ferrule faces on every single mate is crucial. Without it, performance is degraded or lost. In the worst case, permanent damage is transferred by a dirty ferrule face mating with a clean one.
Operational Environment. A wet-mate connector is a sealed, oil-filled, pressure-balanced mechanical device that will be handled in harsh topside conditions in extreme temperatures before being deployed to sea depths of up to 4,000 m.
Operation and Maintenance. High optical performance is required on all lines for up to 1,000 mates. Subsea connectors typically are mated only a few times in deployment and lifetime operation, but the same connectors are used for testing topside where they see many more mates.
Compact Size. Space on subsea equipment structures is always at a premium, and designs always need to be as efficient with space as possible.
This visually demonstrates how a computer assesses the level of correlation between two variables, plotted on the x and y axes, in a predictive model. The process helps determine what correlations are used in a machine learning model. The program has evolved from predicting future well output to showing engineers the many ways their ideas could affect asset performance, including a feature often missing from engineering software, instant estimates of the likely cost and return of each option considered. "As Range was developing the Marcellus, they knew their teams of engineers and geologists were being creative and effective, but as the volume of data and number of databases grew, so did the painstaking job of merging and manipulating data. One of the things that struck me about a year ago was that engineers were coming to me with ideas, with more thoughts and creative solutions than a year or two before," said Ken Brown, Vice President of Reservoir Engineering for Range's Appalachian Division.
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 190652, “Community Engagement, Commitments, and Partnership for Successful E&P Operations in Bolivia,” by Eva Calvimontes and Sergio Eduardo Ayala Sánchez, Vintage Petroleum Boliviana, and Krish Ravishankar, SPE, Occidental Petroleum, prepared for the 2018 SPE International Conference on Health, Safety, Security, Environment, and Social Responsibility, Abu Dhabi, 16–18 April. The paper has not been peer reviewed.
Relationships and engagement with communities in direct areas of influence is of paramount importance for successful exploration and production (E&P) operations. Since the beginning of operations in three major areas of Bolivia, a company has worked very closely with neighboring communities at all stages of design, planning, and implementation of projects and programs. The objective has always been the same: to improve the life quality of the society as a whole and be a partner with the communities.
The company’s E&P operations are located in three areas of Bolivia—Naranjillos, Porvenir, and Ñupuco fields (Fig. 1).
The business units in each of these areas have developed and implemented a social-responsibility program that supports company business objectives and positively affects people, communities, and the environment. A program has been developed that achieves a balance between the E&P interests of the company business and the communities’ expectations and needs. It is carried out through alliances between the company and the communities located inside the areas of influence.
The company’s social-responsibility commitments and ongoing initiatives are categorized into the following five pillars:
Following the core values of each of the five pillars and fully understanding the communities’ needs in the areas of influence, the company has developed and implemented the following steps as part of the stakeholder engagement and social-responsibility approval process:
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 190663, “Building Better Performance Measures for Better Conversations To Provoke Change,” by A.D. Gower-Jones, W.T. Peuscher, J. Groeneweg, SPE, S. King, and M. Taylor, Tripod Foundation, prepared for the 2018 SPE International Conference on Health, Safety, Security, Environment, and Social Responsibility, Abu Dhabi, 16–18 April. The paper has not been peer reviewed.
For the last 40 years, the oil and gas industry has measured safety performance using injury-frequency rates. Industry thinking is based on the premise that, if we do not have injuries, then we are safe and, if we have injuries, we are not safe. This paper examines the fallacy of that premise and the use of injury rates as a key performance indicator (KPI). It argues that, as a KPI, injury-frequency rate is no longer a valid measure.
The Current Situation
As a KPI, injury-frequency rate has served the industry well. It has driven ownership of safety performance as a line responsibility, allowed senior executives to hold managers accountable for performance, forced leaders to notice injuries, and driven many improvements.
A graph showing performance over a 2-year period would be discussed at management meetings, reasons argued, and actions given to business unit leaders. The data could create a discussion along the lines of “Overall performance is clearly going in the wrong direction. We all need to be concerned.” Pointing to one cause would be difficult, and many theories would be put forward on the basis of this data.
Why Measuring Injury Rates Is Misleading
Research into accident causation has revealed much in the last 30 years. Earlier work resulted in the Swiss Cheese Model (Fig. 1), the Generic Error Modeling System (GEMS) (Fig. 2), and the Tripod Model of Accident Causation (Fig. 3). Two software-based products have been produced from these models; Tripod Beta and Bow Tie analysis both are now mainstream.
Safety leaders no longer think that people are the only cause of accidents (i.e., stupid people doing stupid things). They understand that errors and violations are the product of systemic causes. Accidents happen because barriers fail. Barriers fail because of people’s action or inaction. People are generally trying to do a good job, but they are influenced by their environment. That working environment is created by the way the business is managed.
Accidents are complex events with multiple causes. Controls that fail can be a long distance from, and not related to, individuals who are injured. Normally, more than one control needs to fail before someone is injured. Often, those controls are put in place by different people at different times—an operator isolates equipment, a supervisor checks the isolation, and a technician works on the equipment.