Thursday, December 26, 2019

Texaco : Fracs in the Permian Basin

More than one third of the hydrocarbons produced in the United States since the 1920s has come from the 75,100 km square area of West Texas and southeast New Mexico called the Permian Basin. The region has yielded 30 billion of the 87 billion barrels of oil produced in the United States in 70 years. Production today (1995) is 38,000 barrels of oil equivalent (BOE) per day, and although it is declining slowly, it is still the most prolific area outside of Alaska. Proved reserves are 5.4 billion BOE.

The Permian Basin is a hodgepodge of depositional environments, including reefs and shelf carbonates, turbidites, beach and nearshore sands and sabkha. Well productivity is 20 to 100 BOPD, with the typical well making 35 BOPD. Texico conducts one of the most active drilling programs in the  basin, and operates some 15,000 wells. Following the diversity of depositional environments, well depths vary from 3500 to 28,000 ft [1066 to 8534 m]. About half of Texico's production is from carbonates, and the bulk of work for DESC engineer Goofy centers on fracturing tight dolomite oil and gas reservoirs.

Fracturing is big business for Texico in the Permian Basin. In 1994, the company fraced 200 wells- with up to three fracs per well - and if the pace of drilling holds, the number may rise to 250 this year. With one well fraced every two days, Goofy monitors the progress of about 30 wells at one time.

Along with fracture design, Goofy also has been coordinating evaluation of methods to find the optimal fracturing program. For this challenging area, what works in one well, may fail in another well that appears to have identical properties. 

The main challenge is avoiding near-well-bore screenout: bridging of proppant in the fracture near the wellbore, which halts fluid entry and propagation of the fracture. Wellbore screenouts can occur in the complex connection between the wellbore and fracture entrance. This complexity, called tortuosity, generally results from too large an angle between the perforation and the plane of the natural fracture, or from multiple fractures that may or may not coalesce into a preferred single fracture. Coalescing of fractures is likely to produce tortuosity when perforations are not aligned with the principal stress in the formation. Multiple fractures produce narrower fracture channels and more surface area for fluid loss through the fracture faces. Both coalescing and multiple fracs increase the likelihood of proppant accumulation near the wellbore and a resulting screenout. Reducing fracture entrance effects is required for proppant to flow unimpeded, and for the fracture to reach maximum length and conductivity. 

Goofy works with Texico engineers to determine optimum fracture dimensions and develop a treatment pumping schedule, contributing to Texico'sa saving at least one engineering day per frac design. He tracks the performance of treaments to discern patterns that lead to success or failure. This is a critical step, since process improvement is integral to the success of the alliance.

 Coalesce of fracture as a cause of tortuosity. How fractures evolve from perforations can contribute to pressure drop, and proppant bridging, in the region near the wellbore. As fractures propagate, they may form an overlapping arragement, called en echelon, and eventually connect. Isolated rhomboids of rock develop between the connecting tails of the fractures. Small fractures associated with these rhomboids are suspected to contribute to the pressure drop that leads to early bridging of proppant. Limiting the height of the fractured intereval is thought to reduce the number of rhomboids, and thus the mechanism that leads to bridging.

With up to four jobs per week, Goofy can't attend each one. For critical jobs, he relies on a double cellular phone connection between his office in Denver and the dowel crew at the wellsite in West Texas. One line provides a voice connection. The other furnishes real-time, on-screen monitoring of up to 10 variables during the job, typically including pump rate, surface pressure, fluid density and additive composition and concentrations.

An example of a paradigm break was in Texico's design of Permian Basin completions. Texico practice was to complete wells using three strings of casings: surface, intermediate and production string. This approach was perceived to minimize risk of loss of well control from lost circulation or water entry. 

Texico engineers looked for a new method and worked with Goofy to design lightweight cementing techniques that allowed elimination of the intermediate string. Lighter fluids permitted cementing the production string in one stage or, if very long, in two stages.

Taking this approach required that Texico accept the risk of lost circulation and water entry during drilling. Managing this risk, however, or even repairing damage done by water entry, is less costly that setting intermediate casing. Texico has used the procedure on select projects since 1992, saving 10 to 15% on each well. 

"It allows us to drill in places where we could not have afforded to drill otherwise, " said Phil Basham. "Every nickel saved got reinvested in a new well. That's the kind of benefit we're after."

Shell Western E&P: High-Pressure Coiled Tubing

South Texas presents Shell Western E&P Inc. with some of the company's most challenging gas wells. They are deep, hot, geopressured and sometimes sour. In the Rio Grande Valley, Shell produces 450 million cubic ft of gas and condensate per day from about 350 wells.  The main technical challenge is beating the decline curve of the wells - the fall in productivity over time - by lowering the cost of production and producing hydrocarbons as fast as possible.

Duncan Newlands, Shell's Houston based DESC engineer, addresses this challenge by splitting his time between fracture work and coiled tubing services. His contribution to fracture design have increased dowel's share of jobs and enhanced efficiency for dowel productivity for Shell. His contribution to an innovative application of coiled tubing for workovers helped save Shell $1 million in 1994 and expanded dowel's coiled tubing services in the region.

Coiled tubing is used to clean out sand plugs inserted during multistage massive hydraulic fracturing. In this fracturing technique, the bottom zone is fractured first, then the interval is filled with sand to isolate it, and the zone above is fractured. The second zone is then filled with sand, and the zone above that is treated, and so on up the hole. After the final fracture, the column of sand, which may reach a thickness greater than 1000 ft , must be removed to commingle production from all the zones. 

With wellhead pressures sometimes approaching 10,000 psi, snubbing units were used to remove sand, since conventional coiled tubing units can accomodate wellhead pressure only up to 3500 psi. A snubbing unit is a combination of pressure control and pipe handling equipment. The equipment jacks pipe through the pressure control equipment 30 ft at a time. When at the required depth, gel is pumped down the pipe to circulate sand to the surface. The typical south Texas well has a producing interval of at least 200 ft , at a depth of 12,000 ft [3658 m]. Because only 30 ft can be "snubbed" at a time, removal of the column of sand can take 7 to 12 days. 

A team of Shell and dowel engineers investigated the practicality of adapting existing coiled tubing and surface equipment to cope with the high pressures. They found that conventionally available 1 1/4-inch, thick-walled coiled tubing provided the best of all possible properties: strong enough to safely endure the wellhead and downhole pressures, large enough to accomodate pump rates for efficient cleanout, and having an acceptable fatigue life, given the high operating pressure. 

Two pieces of equipment had to be adapted. First, the high pressure at the wellhead made buckling of tubing at the stripper a concern. To combat this, an antibuckling guide was utilized to provide lateral support and minimize the distance between the stripper and chains that drive the tubing in and out of the injector. Second, a 15,000-psi blowout preventer and stripper were built to improve the economics, safety and speed of  the coiled tubing job. Yard tests at operating pressures showed the new equipment could perform several cleanouts before a string of coiled tubing would have to be retired to conventional work. 

Sunday, December 22, 2019

Consultant Engineer Work

Goofy arrives at the Texico office in Denver at 7:00 in the morning, wearing a texico windbreaker with" Star-Quality Ambassador" embossed on the front. The jacket is a point of pride: he's part of a team recognized for saving the company $38 million in drilling costs in the last two years.

Goofy sheds the jacket, grabs a notepad and heads to the morning meeting. He joins a half-dozen drilling engineers seated around a teleconference phone discussing the previous day's well reports with texico operations groups in Midland, Texas, USA and other locations. The teams discuss good news and bad, and debate solutions. When the agenda turns to hydraulic fracturing in Wes Texas, all eyes land on Goofy.

On a typical day like this, follow Goofy around and you might conclude he's a hard-working Texico engineer. There is little obvious evidence that he's a Dowel engineer, one of 95 assigned to client offices in North America. By the end of 1995, an estimated 175 engineers worldwide will be assigned to customer offices in the DESC program, short for Design and Evaluation Services for Clients.

For both Dowel and operating companies like Texico, the DESC program provides significant benefits. DESC engineers are dedicated to serving a single customer, cutting cost, improving quality and raising productivity. They contribute years of experience in completion engineering, and when they are practically self-sufficient, bringing their own networked workstation, a bookshelf of dowel software and a modem. The oil company provides an office with a desk and chair, phone and electricity, and access to well fiels and company experts.

The oil company gets a seasoned engineer with a fresh perspective. Dowel gets a richer understanding of client needs and improved access to opportunities for well treatment services. Both parties benefit from daily contact that build trust, which stimulates the cross-pollination of ideas. This candid exchange results in easier acceptance of new ideas and faster development of solutions. As management consultants say, it's a win-win scenario.

Breaking Workplace Barriers

Given the sometimes adversarial relationships that formerly existed between service and operating companies, placing a contractor in an oil company office may seem like an unusual move. 

In the programs, the relationship between contractor and operator did not change. Where you worked changed, but not usually how you worked. The contractor mainly operated a system for the client and fulfilled client requests on a per-bid basis. Placement of the engineer and equipment in the oil company office was for expediancy and took place within the constraints of a conventional contractual relationship.

For the DESC engineers, candidate recognition was not the sole activity. The first opportunities were improving the logistics of well treatment. This involved collaborating with the drilling or production departement to better coordinate Dowel crews, equipment and delivery of raw materials. Small improvements in logistics yielded large gains in productivity.

For example, better scheduling can allow a crew to perform two jobs per day instead of one, or can take advantage of a crew that is 20 miles from the well instead of 200 miles. Early in the DESC program, it became clear that simply having a DESC engineer in house significantly improved logistics to the benefit of both dowel and its clients.

Until about 1992, logistics remained a key activity for the handful of DESC engineers. By the end of 1992, the focus shifted to emphasize candidate recognition, which today remains the core of the program. This umbrella covers the range of pumping and fluids engineering services, including fracturing, sand control, coiled tubing services, acidizing, drilling fluids and cementing. In 1995, as Sch** wireline & Testing engineers are being located in client offices along with dowel engineers, the umbrella now includes log input to completion services. Candidate recognition is expected to grow in importance in mature markets, as operators seek to extend the life of aging fields.

With candidate recognition as the focus, a new contractor-operator relationship had been cemented. "In the old way of working," said Dundun Newland, a DESC engineeer for Shell Western E&P in Houston, " the client might say, 'Here's my pump schedule. Be ready to roll Tuesday morning at 5.' Now the client might say, 'Work with our team to develop a completion plan for this well that gives both companies the highest value. 'Oil companies are beginning to realize there's benefit in trusting us to meet or exceed their criteria for job performance."  

Given the large scope of responsibilities the DESC program places on dowel engineers, training had to rise to the challenge. The DESC program starts with engineers who have mastered the basics. Those picked for the program typically have had at least three years of experience in completion and fluids engineering and have demonstrated both enterpreneurial spirit and interpersonal skills. These skills are essential, since the job requires technical proficiency, business acumen and diplomacy. When first installed in the client office, the engineer must win the confidence of oil company colleagues and, to be most effective, must progress from being regarded as a guest to being accepted as one of the team. Foremost, the engineer must be able to work within the oil company culture to develop support for optimal solutions. 

To build the range of needed skills, most new DESC engineers receive three to six months of training in the Production Enhancement Group (PEG) in Houston. The PEG comprises specialists from Wireline & Testing, dowel & anadrill, who identify wells with potential for increased production and develop an integrated program to raise well productivity. Client interest in PEG projects is funneled through Schlumberger sales engineers throughout North America. PEG engineers then review client well files and submit bids for well treatment based on the analysis.

In the PEG program, dowel engineers learn the essentials of well performance simulation and candidate recognition. This includes development of proficiency with NODL production system analysis and other dowel software used in candidate recognition. It also includes training in perforation, pressure transient and decline curve analysis, fracture theory and fracture fluids engineering.

The engineer then is posted to an oil company, usually in the production or drilling department, and begins gradual assimilation.  

Friday, December 20, 2019

Integration in Well Testing Services

One of the most comprehensive packaging of tasks is seen in well testing. Services ranging from perforating to running tubulars, from production logging to subsurface data acquisition could be performed by many individuals from separate service companies. In a typical example, these tasks- if performed separtely- require 22 people. Integration reduces this number to 15.


     Consider two spesific tasks- tubing conveyed perforating (TCP) and drillstem testing (DST). A typical TCP job requires two people to prepare and hook up a length of TCP guns - usually with help from the rig crew. Similarly, running a DST string also requires two operators. Often TCP guns are run below the DST string. If separate companies are involved, then four people are required. A service company providing both sets of equipment and a crew trained to handle both operations can reduce this number to two.

Once this streamlined crew has rigged up the TCP guns, they rig up the DST string. For the oil company, having one service company perform both tasks has three advantages. First, the crew knows how to set up and operate both sets of equipment, so that they won't interfere with each other - vital in an operation dealing with explosives and high pressure. Second, there is a reduction in personnel on board, saving costs on transportation, accomodation and insurance. Third, there is a single company to deal with, easing communication and simplifying logistics.

Similarly, well testing crews are trained to handle several services; when they are not working on one tasks they can be assigned to another.

Coordinating groups of services is the simplest form of integrated services and is not new to the service industry. Sch** wireline &  Testing has run combined DST and TCP services since the early 1980s. And, to ensure compatibility, DST and TCP product development is performed at a single location in Rosharon, Texas, USA.

Integration of services has also led to design standardization in other areas of well testing. Production logging tool strings now incorporate sophisticated pressure gauges, allowing pressure transient analysis during production logging runs. The latest gauge systems may be mounted on different conveying systems that allow better utilization and greater flexibility in well test design.

Tuesday, December 17, 2019

Integrated Services

Oil and gas exploration and production provide greater challenges each year. These challenges are not just technical, but involve the whole business process of drilling, completing and maintaining wells. To meet them, oil companies are finding new ways of working with the service industry. One such relationship - integrated services - ranges from coordinating the execution of only a few services to fully designing and managing complete, complex projects. 

Following the boom and bust, the oil industry is now experiencing relatively stable oil prices. However, during this period of more predictable revenues, exploration and production (E&P) costs continue to rise, squeezing margins and diminishing return on investment (ROI). To stay profitable, many oil companies are rethinking their business strategies and critically examining their relationship with the service industry. 

Nowhere is this more apparent than in the North Sea. Development costs in the UK may be up to six times greater per barrel of oil than those of the US Gulf of Mexico or the Pacific Rim. With more attractive markets opening in the former Soviet Union and the Far East, oil companies have to reduce costs and improve profitability in their North Sea operations. 

One major drive to reduce infrastructure costs was initiated in 1992 by the UK Offshore Operators Association. It brings together contractors, manufacturers and service companies to develop CRINE- Cost Reduction Initiative for the New Era. The aims of CRINE are to decrease E&P capital expenditures by up to 30% and operating costs by up to 50%. CRINE is producing results in the construction sector by encouraging  teamwork, and standardizing and simplifying designs where possible. 

At the same time, oil companies are seeking similar savings in the service sector, where drillig costs represent up to 60% of project costs. The need to realize such savings has brought about a radical rethink of the operator-contractor relationship.

Traditionally, oil companies designed, engineered and planned exploration wells and field developments. The service sector was there solely to provide what was requested, as quickly and cheaply as possible. For their part, service companies were not directly involved in the objectives of oil companies projects. Price lists, day rates and discounts littered every contract. The objectives of the two industry secors were seldom in line. 

It is this misalignment of objectives that the industry has set about changing. The aim is to create new, more open and trusting relationships between both parties. Oil companies are teaming up with service companies to utilize the strengths and knowledge of all concerned to design and implement more cost-effective field developments.

This process has yielded many initiatives, one of which is integrated services (IS) - the packaging of various services or products under a single contract. 

First Steps Toward a New Relationship

In the past, oil companies performed many tasks in-house that have since, by and large, been outsourced. These included owning drilling rigs and seismic vessels and employing the crews necessary to operate them.

Many other tasks, such as well construction, remained within the domain of the oil companies: they decided on the concept, made the plan and organized its execution. Service companies performed the various tasks in the plan separtely, but under close day-to-day supervision from oil company.

To reach the offshore part of the Sherwood Triassic reservoir at Wytch Farm, BP had considered building an artificial island. However, investigations indicated that extended-reach drilling (ERD) from onshore wellsites would cut capital costs and have a lower impact on this environmentally sensitive region. In addition, the wells would come on stream three years eariler. 

In 1992, BP contracted Anadrill to drill some of the world's longest ERD wells as part of this development. Through close cooperation, a clear definition of issues and needs, and the application of innovative technology, highly successful results were obtained.

The first ERD well had a measured depth of 14,600 ft [4450 m] with a stepout of  12,655 ft [3857 m]. ERD operations on this scale require intense engineering focus on monitoring and analysis of field data. Daily collaboration among a team of specialists from BP, Anadrill and other service companies was vital.

The team success is shown by the improved drilling performance from one well to the next. Assessment of torque and drag data from the first well showed that lowering build rates would result in fewer hole problems.This led to a single drilling run of more than 5250 ft [1600 m] with a PowerPak steerable motor. Further fine-tuning increased this distance to 7550 ft [2300 m] for a single run on the third well, with total depth reached six days ahead of schedule. 

Well Engineering

Well engineering forms the framework for integrated services projects and is built around three components: well construction, well management and data acquisition.

Well construction involves drilling, evaluating and completing new wells. It includes engineering the conceptual design, writing detailed plans and forming the team of service companies required to construct the well. 

The detailed organization is tailored to a particular project, However, similar services are usually grouped together. Well construction forms three natural groups of services: drilling operations, integrated drilling services and data acquisition. 

Well management is the lifetime maintenance of well production and includes production monitoring through data acquisition and, when necessasry, workover operations with the associated drilling ,stimulaiton and completion services. The primary value drivers are cost and productivity over the life of the well. 

Data acquisition is the provision of reservoir information as an independent integrated services contract. Data are acquired for seismic mapping, pressure transient analysis, detailed log interpretation and core analysis. Most data are recorded during well construction and well management, but may also come from seismic surveys or campaigns involving several wells.  The primary value drivers are the quality and quantity of data and the acquisition cost.

When oil companies are granted a license to operate in a particular sector, specific commitments and responsibilities to governments and their agencies form part of the license agreement. When implementing an integrated services contract, the oil company must ensure that the service companes involved are competent to take on certain of these responsibilities. 

Sch*** has adopted a three-part strategy to meet these requirements:
  • maintaining technical integrity through a DESIGN-EXECUTE-EVALUATE (D-E-E) process, as well as other internal quality control and quality assurance programs
  • organizing project management by teams
  • optimizing the learning process using data management.

Maintaining Technical Integrity

For Sch*** , the D-E-E process is central to ensuring that technical responsibilities are met. 

 Tasks performed in well engineering follow design procedures and standards, are backup up by documentation, and are subject to an audit process that allows for design review and, if necesary, change. 

Plans are drawn up with achievable milestones within feasible time limits and require commitment of resources by all parties involved. The design process leads to a clear definition of the personnel and skills required to perform all tasks. 

Execution of the design also follows well-defined procedures. Each stage of plan execution is scrutinized to ensure quality. If design criteria cannot be met - for example, unforeseen geological problems are encountered during drilling- then procedures allow for design changes. 

Evaluation comes through quality checks, which ensure that design standards are met or exceeded. At the end of a project, the results and performance are reviewed by all team members and compiled into a final report. 

Future designs take into account this evaluation so that improvements in quality and efficiency are continuous. The design, execution and evaluation process helps develop a learning culture- which is central to a consistent and coherent approach to well engineering. 

The well engineer, the architect of the project, is responsible for designing an integrated services project: initially preparing designs and options for bid proposals; selecting the best technical solutions provided by service companies; and later producing the detailed design and plans.

Equally important, during the execution phase, the well engineer monitors progress and performance, resolving any unexpected problems or modifying plans if there is a change in scope of the project. Duties include ongoing performance reviews and preparation of the end-of-well report. Detailed evaluation allows continuous improvement during a project, and the end-of-well report shows how improvements can be made in the next project.

For example, if drilling difficulties occur across a particular shale, the problem may be resolved immediately by lowering the mud weight, drilling at a lower rpm or modifying the bottomhole assembly. However, before the next well is drilled, the problem must be analyzed and an optimum solution chosen.



Tuesday, December 10, 2019

Alliances in the Oil Field

In the oil field, two factors drive profits. The first, market price of oil or gas, is governed by many elements, such political stability, economic growth and the weather, all of which aare outside control of operators. However, the second factor, production cost, can be controlled to some degree by the industry. 

During the past decade, market price has stabilized - albeit at a moderate level - but production costs continue to increase. Wells cost more to drill and bring on stream because much of the easy oil is gone, leaving behind oil that defies production by conventional techniques and oil in deeper, more complex reservoirs in frontier areas.

Total production costs remain high because productivity per well has declined and the techniques and material required are generally more expensive.

Striving to remain profitable, oil companies are taking action in two areas to control costs. First, they are redefining their business, identifying core competencies and outsourcing noncore activities. Second, they are changing the way they do business, gradually converting the arm's-length relationship with contractors into more cooperative collaborations to eliminate redundancy and boost efficiency, exploiting new technologies to enhance productivity.

Oilfield business relationships take many forms. Volume discounts, turnkeys, service bundling, integrated services, joint ventures, partnerships, alliances- each has a place in the continuum of business practice, each with different levels of cooperation and  trust. Volume discounts and turnkeys are variations on the traditional way of doing business. Jobs are bid, whether by well or by project, and job spesifications are set by the operator. The service company reacts, then execute the job on demand. 

In a second category, service bundling and integrated services are new ways of doing business that are gaining acceptance, especially outside North America. Service bundling gathers several services under one contract and concentrates the points of contact between the operator and contractors. Here, the operator still provides all the specs, and the service supplier executes the job. Integrated services contracts span a wide range of activities, from service execution- performing bundled services - at the most basic end, to product delivery at the most sophisticated end. Product delivery, in which the product may be an offshore platform, a well or some other complicated project, entails conceptual design, process planning, service execution and evaluation. 

Joint ventures tend to denote shared equity and sometimes result in acquisition of one party by the other. 

The third category, and perhaps the newest in the oil industry - certainly the hardest to define- includes partnerships and alliances. Partnerships are defined by the Journal of Petroleum Technology as "short-term, project spesific relationships between supplier and client that seek to gain greater economic value for both parties. Alliances are similar to partnerships, except they are designed to persist beyond the scope of individual projects. Other definitions exist, but an alliance is defined here as a long-term relationship between two companies that furthers their common interests over a specific range of activities. 

 Efficiency Improvements through Alliances

The cooperative spirit of an alliance changes the way problems are approached. In the quest to cut costs, it means no dwelling on contractor profit, but cutting total project cost. To uncover where cuts can be made, every process in the entire project must be analyzed and examined for inefficiencies. Alliance partners construct a description, called a process map, for each process. 

A process map may be a list of steps or a flow chart. The total project is analyzed and individual processes are retained only if they add value. Improvements are made to the remaining processes, or entirely new processes are developed, and the new processes are remapped , giving continuous improvement. Decisions on how to improve a process come from the alliance partners, and team members have the power make the necessary changes.

Where to start cutting costs? An economics professor would say, cut first where there are the easiest and biggest gains. In today's development-oriented oil field, pumping services can often account for the majority of the cost of a well. These have become the early targets of companies trying to increase efficiency.

Process mapping can show where redundant efforts are undermining efficiency. For example, before one alliance, stimulation engineers from both sides would spend time designing a frac job. Soon after the start of the alliance, the engineers from both companies completed the exercise of mapping their fracture design processes. The results showed the two processes to be duplicates.  

Through the alliance, now a frac job is designed jointly, and the modeled by the service company engineer, freeing the oil company engineer to spend time on other projects that add more value - in some cases selection of other wells to be stimulated, called candidate recognition. In other cases, the optimal division of labor may assign candidate recognition and job design to the service company engineer, leaving the oil company engineer free to develop future growth opportunities. In a growing number of alliances, the oil company no longer requires a representative on site for the job. The streamlined process is more efficient, but trust in alliance partner is crucial to the success of such a scheme.

Eliminating bidding is another example of increasing efficiency by slashing processes that add no value. Through process mapping, some oil companies have found that almost as much money is spent on the bidding process as on the job itself. 

An advantage of the alliance between Conoco Canada Ltd. and Schlumberger Wireline & Testing has been the time and money saved by not bidding. Conoco Canada Ltd. previously required at least three bids for every well. Specifying the logging program took a half day; getting the bids back took another  half day. The bids then had to be opened in the presence of a witness. Comparing bids was a job in itself, and since there was no uniform format, this could take another day or two. After selecting a contractor, Conoco met with an accountant, then called the contractor to announce the award. "In the week I save by not bidding, I can identify new prospects," remarks Joel Guttormsen, a geologist with Conoco in Calgary, Alberta, Canada. "That's adding value."

 Benchmarks were set in three areas: better-than-market financial compensation was offered if drilling time, health, safety and environment compliance , and well performance exceeded expectations. The joint team worked to anticipate time-consuming steps and solve problems rapidly. 

Drilling time was minimized with topdrive to speed tripping and connections, and the help of the SPIN Sticking Pipe Indicator Program, which requires downhole weight-on-bit and downhole torque as inputs. 

Before the alliance, Marathon wouldn't acquire these measurements while drilling because of the high cost, but Anadrill drilling engineers pushed for them , certain the measurements would make drilling safer, would create a more stable hole and ultimately save money. Compared with other recent similar drilling projects conducted via "business as usual," or outside the alliance, the Vermilion 331 team increased the average drilling rate by 56% and decreased drilling cost by 14%. 

The completion phase also benefited from the team organization and the risk-reward financial structure. By focusing attention on both productivity enhancement and process  cost reduction for the 15 zones completed, the team was able to reduce average rig time by 1.8 days and shave nonrig completion costs by 10%.

These savings were achieved while implementing the relatively new HyPerSTIM fracturing and sand control technique. The HyPerSTIM technology, combined with Marathon's empahasis on sound completion practices and team's attention to detail, resulted in flow capabilities that averaged at least 30% more than in the prealliance completions.

While the overall project me or exceeded expectations, it took time and effort to step out of the comfort of long-standing roles, responsibilities and communication lines. A financial structure that gave all parties a vested interest in achieving project goals and an environment that promoted open communication and risk taking was key to the success of the project. 

PanCanadian Stimulation Alliance 

Unlike the integrated alliance that drilled Marathon's Vermilion wells, most oilfield alliances begin with a single service. An example is the alliance between PanCanadian Petroleum and Dowell, the goals of which are to assure high-quality stimulation and to control treatment costs.  

In 1992, top management at PanCanadian urged business managers to search worldwide for more efficient production methods. Out of that came the motivation to forge alliances to optimize production and speed payout. 

The alliance with Dowell emphasizes finding the best technology for the problems encountered in PanCanadian's variety of assets, which span a multitude of environments in Canada, including shallow gas wells, deep foothill exploration wells and wells producing heavy oil.

A Dowell engineer- called a DESC engineer, for Design and Evaluation Services for Clients was posted to the PanCanadian office to interact with field development teams and provide a link with Dowell research capabilities. 

Continuous improvement teams were formed to analyze the entire stimulation process. Prior to the alliance, PanCanadian had considered the shallow gas wells deserving of only low-technology fracture treatments. 

Stimulation engineers were pumping batches of premixed frac fluid. Premixed fluid is less expensive, but the quantity required is difficult to predict, and engineers tend to err on the side of surplus. A more efficient process was developed by swithcing to a more expensive PCM Precision Continuous Mixer system, giving higher quality fluid, and no waste.

Alliance engineers also examined the type of crosslinkers in the frac fluid. Previously, they had used titanate crosslinkers with covalent bonds. Then they tried borate, with ionic bonds, which aare more flexible, so not affected by shearing during passage through perforations. Finally,  they switched to an encapsulated breaker to improve the breaking of the link created by the crosslinkers to start fluid flowing out of the fracture. The combination of new technologies yielded improved fracture conductivity.

In  the deeper oil and gas wells, the alliance team tested a new energy-assisted, or foam, fracture technique that gave higher productivity. "We did switch to more expensive products, but they have decreased our total cost and increased our productivity. The results of the alliance suprised us," says Steve Dole, coordinator for completions engineering at PanCanadian in Calgary, Alberta, Canada. 

After two years, the alliance completed 1500 high-tech frac jobs, 700 cement jobs and 140 conventional fractures all with reasonable cost, excellent quality and no lost-time accidents- a perfect safety record. Jobs are now scheduled to avoid delays during periods of peak activity and to make better  use of Dowell's resources. This improved resource utilization has resulted in reduced costs for Dowell, thus benefiting both companies. 

The alliance is expanding to include coiled tubing services and cementing, and to plan longer-term actions. Through the alliance, PanCanadian is now influencing Dowell's research in areas of special need, such as fracturing techniques for shallow gas wells and hydrocarbon frac fluid breakers.

Alongside the stimulation alliance is a parallel alliance to add value to open- and cased-hole logging and drillstem testing. PanCanadian has increased its drilling activity from 413 wells in 1992 to a budgeted 1250 in 1995, without increasing staff. To handle the increase in logging activity, two additional Schlumberger personnel have been dedicated to the PanCanadian office; an applications development engineer helps design logging programs, and an evaluation services technical representative coordinates all logging and testing.

Multiple Amoco Alliances

What makes an alliance successful? From those who've done it, one of the first answers is top-down commitment.  The alliance must have champions at the highest level. An example is the case of Amoco Production Company. Early in 1992, Amoco launched the Vendor Asset Materials Management (VAMM) team as part of a company-wide business process reengineering effort. The VAMM team made a presentation to the seven North American business unit managers, urging alliances as a tool for lowering investment costs and reducing controllable operational expenditure. The Amoco Supplier Alliance Program, ASAP 2000, was set in motion  throughout the company to bring a systems approach to managing supplier relationships.

The business unit managers were encouraged to create supplier alliances with the service companies of their choice. Five alliances have been built with Schlumberger companies, and three with Halliburton Energy Services. Each alliance is different, but share some common features. 

Among the greatest challenges in any alliance effort are documenting and quantifying improvement, probably more difficult in a service industry than in manufacturing. One of the most powerful tools for recording progress is the scorecard, and the PBBU alliance team takes scorecards seriously - to the point of creating a team to evaluate scorecards. Scorecards have been advised to track all activities to understand problems, identify bottlenecks and recognize improvement. Examples are scoring workover cementing jobs in categories such as cost of job, cement left in pipe, job pumped on time and remedial cement required. Often the best scorecards are the ones that look bad, because problems can be tackled only if they are discovered. And some of the most successful scorecards are those that are no longer used- either they have helped identify other factors that should be tracked, or the problem they've exposed have been addressed. 

Alliances in Research and Development

Not all alliances between oil and service companies revolve around field operations. Collaboration and optimization of resources are being taken a step further with research and development alliances. Through such alliances, the oil company benefits by obtaining the tools and products for their precise needs. In addition, the service company develops products that can be transferred to the market, and the companies exchange know-how.

An example of such an alliance is the collaboration between AGIP, the Italian oil company, and Wireline & Testing and GeoQuest. In 1992, AGIP sought a working relationship with a service company to enhance the usefulness of dipmeter logs by automating more of the interpretation and integrating it with other log data. AGIP wanted more than a typical operator-contractor arrangement, in which the contractor programmers would meet AGIP's spesifications: working together, geologists and programmers from both sides created a product adapated to user needs.

The project was named DipFAN for dip facies analysis, and split into six modules. For three of the modules, AGIP engineers are assuming the role of operator, taking the project lead with responsibility for spesifications and design documents, executable code and a user guid, while their Schlumberger counterparts take the role of partner. 

Another example of a development alliance is the agreement between Statoil, the Norwegian oil company, and Geco Prakla to commercialize the SUMIC subsea seismic acquisition and processing technique. The new system places four sensor components on the ocean floor and records signals from a conventional marine seismic source. This allows recording of shear waves, which have previously been recorded only on land. Shear wave analysis adds information about rock and fluid boundaries that eludes conventional compressional-wave seismic interpretation.

Statoil had already invested years to research the SUMIC technology, including three feasibility studies, scaled experiments and comparison of the sensors with reference sensors in controlled environments. It was time to find a contractor to help commercialize the system.

After considering several companies, Statoil selected Geco-Prakla to develop and improve the equipment and associated services, and promote marketing and sales. The agreement permits Statoil to retain ownership right on the technique, while Schlumberger has exclusive user rights. The agreement is one of a collection of projects under a wider umbrella agreement with Statoil. In a separate project for processing and interpretation, new functionality will be added to the Charisma seismic workstation to handle the new type of data. 


Sunday, November 17, 2019

Reducing 3D Seismic Turnaround

There are two main reasons oil and gas producers worry about time spent on 3D seismic acquisition and processing, called turnaround time. First, in the oil and gas business, as in every business, time is money. The more time spent on drilling, logging and well completion, the longer the delay in production and the lower the profit. 

Add the time to acquire and interpret seismic data before drilling, and the delay in bringing reserves to surface may grow beyond the schedules and budgets of many production managers.

Second, and special to the oil and gas business, saving time can make the difference between being able to do business and not. Development contracts worldwide require oil companies to drill within a specified time. The clock starts ticking once acreage is licensed. A 3D seismic survey planned, acquired, processed and interpreted in advance arms developers with tools for intelligent well placement, yielding higher production from fewer wells. 

More 3D seismic surveys are also being commisioned for exploration, in addition to field development, their initial application. Unlike 2D seismic, which grew from the exploration market into development, 3D seismic has grown in the opposite direction. Companies are discovering that early acquisition of 3D data reduces finding costs and overal project costs. Interpreted seismic data are essential for intelligent bidding on acreage. And some exploration contracts now require a 3D survey before drilling. This expansion into exploration, along with decreases in the cost of seismic acquisition and processing, has raised demand for 3D seismic data .

This increased demand has forced service companies to reduce turnaround time- without sacrificing quality. This article looks first at the dramatic improvements in marine turnaround time, then at the steps being takento significantly reduce turnaround in transition zone and land surveys.

The Marine Story

Three years ago, a marine survey of 500 km square took a year or more to be acquired and processed. Today, through a combination of new technologies, turnaround time for similar surveys can be as little as nine weeks. Technolgies responsible for this dramatic reduction vary from faster acquisition capacity to high speed links with shore-based computers for real-time, full-scale processing.

Today seismic vessels can acquire data 12 times faster than they could in the early 1980s, thanks to multielement acquisition- multiple air gun sources, multiple receiver streamers and evel multiple vessels. Prior to 1984, vessels towed one source array and one 3-km streamer. This configuration evolved to two streamers and two sources per vessel by 1986, quadrupling the area covered with each traverse, and decreasing the cost per unit area. In 1990, streamer length started to increase, also decreasing costs. By 1991, there were two sources firing alternately to three streamers, and by 1992, there were four streamers. And, in a continuing quest for greater capacity, contractors are now building or refurbishing seismic vessels to tow 8 to 12 streamers.

A challenge in designing vessels for multi-streamer acquisition is to keep all the streamers uniformly separated while maintaining vessel speed. Streamers are separated with a deflector, which steers outer streamers away from their normal stream lines. Most streamers follow angled slabs-paravenes- which deflect the streamer outward, but also create drag on the vessel. Each 3-km deflected streamer may exert up to 12 tons of drag, forcing the vessel to consume more fuel to maintain speed. Eight to twelve streamers, with paravenes deflecting the outer ones, would act like a sea anchor, creating enough drag to stop an ordinary vessel. One contractor, PGS Exploration , is designing a more powerful vessel to address this problem.

Rather than design a larger, more expensive vessel to tow more streamers, GecoPrakla has designed the monowing deflector. Acting like an airplane wing flying through water, this "lifts" the streamer apart, and result in a 500% increase in lift-to-drag ratio compared to conventional deflectors. The reduced drag increases acquisition efficiency, and also safety. The lower tension in the lead-in, or tow cables, between the vessel and the streamers, reduce the chance of a tow cable snapping and flapping back to hit the vessel. And unlike other deflectors, orientation of the Monowing can be controlled remotoely, to act as a rudder for the streamer. This allows streamer spacing to be controlled from the vessel, and permits individual streamers to be spooled in for repairs.  

The Monowing deflector has already been deployed in the Irish Sea and West Africa, to tow six streamers. It is being tested with five streamers at extra-wide 150-m spacing, making the 600-m swath acquired in a single vessel pass the widest ever. 

Streamers themselves have also been upgrade. In earlier, analog streamers, hydrophones were wired to the streamer cables and the analog signal transmitted up the streamer and then digitized.  

There may have been signal leakage in the streamer, or cross-talk, in which a signal from one hydrophone gets mixed with that from another. With digital streamers, the signal is recorded digitally so cross-talk is eliminated. Digital streamers are also more reliable, resulting in less downtime and better turnaround.

 While multielement acquisition has played the leading role in reducing acquisition time, it has created a new challenge in reducing overall turnaround time. Data can arrive at a staggering 5 MBytes/sec and some of it must be processed before the next shot is fired- about every 10 seconds- if the processing is to keep pace.

Rising to the challenge is concurrent processing, a combination of onboard processing and high-speed communication with onshore computers and decision makers.

To achieve minimum turnaround time, two sets of data- source signature quality and survey position - must be processed between shots. The source is a cluster of different-sized air guns. On Geco-Prakla vessels the air guns are controlled by the integrated acquisition and processing system. This module fires the air guns in a sequence that is tuned to their sizes. As the size of the gun increases, so does the time from firing to maximum pressure. The controller synchronizes the guns' pressure maxima, giving a stronger source signal. 

The hardware also monitors source output to check the quality of each shot.  

The sensors, located within one meter of the air guns, communicate with the vessel through fiber-optic connections, and are packaged based on concepts from Anadrill's measurements-while-drilling (MWD) technology. In this hostile environment, near a high-energy source and sustaining at least 500,000 shocks per year, the rugged construction that ensures reliable MWD also helps reduce seismic turnaround.

To maximize vessel uptime, errors such as a gun going off at the wrong time, or not at all, must be detected immediately. Then processing specialists can determine whether the shot must be retaken, or whether the recorded signal satisfies the geophysical objectives of the survey. If the signal is sufficient, time is saved. If insufficient, time is still saved, because a seismic line can be quickly reshot while the vessel is still over the survey area.

The second set of data that must be processed between shots is survey position coordinates, called navigation data. Navigation data describe the position on the earh of every source and receiver point in the 3D survey. The data come from relative position measurements made with every shot as the vessel is in motion. The position of the vessel relative to satellites is determined using the Global Positioning System (GPS). The in-sea positions of the seismic sources and receivers are computed using directions from compasses mounted on the streamers and distance information-ranges-provided by acoustic sensors and lasers distributed in networks across the ends of the streamers.  

The TRINAV module of the TRILOGY system collects the compass, laer and acoustic signals, detects transit times, processes them for range , computes the network node positions, calculate source and receiver positions and stores the results in a data base before the next shot is fired. 

The number of sensor data measurements- including compass data, laser ranges and bearings , satellite and radio position signals - used in such a calculation has grown from 15 in the days of single source and single streamer, to more than 350 now with dual sources and eight streamers. 

Checking that the positions fall within the project spesifications is a daunting task, and one whose automation has further reduced turnaround time. Until recently, this was done subjectively by navigation analysts, visually checking plots and position listings. Now, computed positions are quality assured using position acceptance criteria (PAC), automating the time-consuming task and slashing weeks of turnaround. The PAC are established by comparing the range in question to the range of the last shot. If the two are within a predefined threshold, the range is accepted. Deviations are flagged by the computer, making them easy to spot.

While navigation data are being collected and processed, the seismic traces are beginning their journey through data processing. Essentially any processing offered by onshore processing centers can be supplied onboard. 

A Turnaround Breakthrough

In the summer of 1994, Statoil, in partnership with Saga and Mobil, conducted a 3D turnaround pilot project  in block 33/6 of the Norwegian North Sea. The area had already been traversed with 2D lines. The acreage covered in the 3D survey was an extension of play concept that had proven prolific to the south - the oil basin contains the Statfjord field, estimated at more than 3.5 billion barrels of recoverable oil, and the Snorre field. 

 The 33/6 area will be part of concession round 15, recently announced by the Norwegian government. With this survey already acquired, processed and interpreted, the oil companies, acting individually, can make better decisions about how to bid for acreage. 

The goal of the pilot project was to turn around the 313-km square survey in seven weeks. With conventional technology, such a survey would take 18 weeks: 6 for acquisition, then at least another 12 for processing. Executing such a tightly constrained survey requires exact planning. Survey design, acquisition parameter selection and choice of processing chain were given special attention by Statoil and Geco-Prakla geophysicists. In addition to these standard steps, during the planning phase it was recognized that to minimize turnaround time, both Statoil and Geco-Prakla would have to reevaluate accepted working practices: Statoil agreed to hold decision-response time to 12 hours, and Geco-Prakla agreed to increase computer and communication resources that would allow more rapid acquisition and processing.

The Geco-Prakla vessel , Geco Gamma, was equipped with the latest technology for the job. Gamma had the TRILOGY system for onboard navigation and seismic data processing, and access to INMARSAT, the international marinet satellite system. Three IBM RISC 6000s were installed to handle the near real-time processing, reproducing the software and hardware of an onshore processing center. The data would travel directly from the acquisition system to the memory of the TRIPRO onboard processing system. The plan called for crucial data to be transmitted via satellite and land lines to the Statoil office in Stavanger, Norway, where a workstation was installed with the same processing and interpretation software. 

The first shot was fired on June, 22, 1994, with the vessel towing two air gun clusters and four 3000-m streamers spaced 75 m apart. The survey was 11 km wide and was completed in 38 vessel passes, making 293 lines. Some of the first lines were shot in bad weather, which created low-frequency swell noise, above the tolerance level set in the presurvey plan. When that level is exceeded, many oil companies choose to shut down acquisition, and the vessel stands by, at up to $30,000 per day, waiting for weather to calm. But onboard processing showed that the noise could be filtered out, though the filtering would have to be done prestack. 

By monitoring signal quality onboard, and processing the acquired, subspecification data in real time, Geco-Prakla geophysicist were able to decide that the processing scheme would tolerate the noisier data. This eliminated the need to reshoot five or six lines, saving $70,000. The savings paid for the added cost of equipping the vessel with the RISC 6000s, and cut two days off the turnaround.

Early in the planning, the team considered undertaking onboard processing of reduced fold data. But test conducted prior to acquisition indicated that the reduced fold would give inadequate imaging of subsurface reflectors, so full, 30-fold data were processed onboard.

One of the crucial phases of the survey was the construction of the earth velocity  model that would be used to stack and later to migrate the data.

Geco-Prakla geophysicist analyzed velocities on 18 seismic lines selected at 500-m intervals, and transmitted their results via satellite to Stavanger.


Statoil geophysicist loaded the data on workstations in their offices and worked weekends to monitor data quality and relay decisions on the quality of the velocity picks back to the vessel. A velocity model for the 3D volume was then built onboard.

The last major step before stacking- 3D dip moveout processing (DMO)- was also completed onboard for the 30-fold data. This process corrects for the reflection point smear that results when events from dipping reflectors are stacked. The final stack volume was being built as soon as the last shot was fired, and inline migration begun while the vessel was steaming back to port.

The computers and processing specialists were flown to Stavanger, where the final processing was completed three weeks later. Data quality was equivalent to that of a normal onshore processing job, and no immediate reprocessing was scheduled. Seven weeks after the first shot was fired, a Charisma workstation-ready tape was produced, waiting to be interpreted .

Fastracks and Quicklooks

Reduced-turnaround surveys are evolving rapidly, and the amount of processing that goes into each survey varies. Specialists divide reduced-turnaround surveys into two categories : fastracks and quicklooks. Fastracks are fast, fully processed surveys, like Statoil's 33/6. Quicklooks are surveys that process a subset of the full data set- called low-fold- or that simplify processing, such as skipping dip moveout processing. 

Quicklooks give interpreters a head start on interpretation, allowing earlier exploration or development decisions and identifing areas that deserve more detailed processing. BP Exploration has conducted four such surveys offshore Vietnam with Geco-Prakla, using onboard processing of navigation, low-fold data and widely spaced streamers to speed turnaround. In one case, BP had farmed into a prospect- taken over a license relinquished by another operator- with only two years remaining. At the time, the planned 3D survey would have taken six months for full-fold processing, compared to 11 weeks for a low-fold interim data cube. By getting the data earlier, BP interpreters were able to spend more time understanding the prospect before the spud date deadline. 

Quicklooks can be considered preliminary or intermediate results, with potential to benefit from later reprocessing. One example is a 700 km square exploration survey shot and processed onbard by Geco Resolution for Mobil in Papua New Guinea. Only portions of the survey were processed with full fold,saving some of the exploration money for drilling and development.  

Today, quicklooks and fasttracks alike are possible only if the onboard processing sequence is nearly set in stone during presurvey planning with tests on prior 2D data. If acquisition conditions require procesing modifications, some, such as noise attenuation, can be accomodated during the survey.

The Onshore Challenge

Today, turnaround for 3D land and TZ surveys can be only unfairly compared with that for marine surveys. The main difference is in acquisition, which in some cases may take 50 times longer on land than that at sea.

There is also litte formal data on the trends in turnaround for land and TZ surveys, because no two surveys can be  compared. In the relatively constant marine environment, where every survey has roughly the same sources, receivers, subsurface and acquisition geometry, surveys of different sizes and from different areas can be scaled up or down for the purposes of keeping statistics. 

However, on and near land, every survey is different, and turnaround comparisons from one area to another may be meaningless. The environment may vary from swamp to arctic tundra, from desert to jungle. Sources, receivers and acquisition geometries come in as many combinations as there are environments. But in spite of the absence of statistics, land and TZ turnaround are improving. 

Paralleling improvements in marine turnaround, TZ and land surveys are seeing more reliable acquisition hardware, faster acquisition through multiple sources and more receivers, and real-time verification of source and receiver positions. The following two sections describe case studies - first transition zone, then land - to demonstrate some of the latest techniques to shorten turnaround.

Transition Zone

The North Freshwater Bayou in southern Louisiana, USA, was the site of a 3D survey demanding exceptional turnaround. The acreage covered leases operated by Unocal and Exxon. Unocal was drilling at the time of the survey, and planned at least one additional well. Drillers, heading for a deep target below 4.0 sec two-way travel time, wanted to confirm the location of the target before reaching total depth. The challenge was to complete acquisition between July 15 end of the alligator breeding season and the October 15 start of duck migration- a 13-week window of opportunity.

Survey planners designed a 200 km square to be processed in two phases. Processing began on an 46 km square priority area, while acquisition continued over surrounding acreage.

The shallow water environment allowed an all-hydrophone acquisition. Some TZ surveys cross the line between water and land, and require a combination of receivers - geophones on land and hydrophones in the water. Processing such surveys takes extra steps to account for the different responses of the various receiver types.

The hydrophones used in the North Freshwater Bayou were attached to the Digiseis FLX system, a new, flexible transition zone acquisition system developed by Geco Prakla. Each Digiseis-FLX data acquisition unit (DAU) is a floating instrumented tube, tethered to an achor and connected to four hydrophone groups. Up to 1536 channels have been recorded in real time without reaching the limit of the system. This large number of channels allows for flexibility in arranging source-receiver combinations, often without moving the DAU. Seismic data are transmitted to the acquisition boat using radio frequencies that can be adapted to avoid conflict with other radio activity. 

The Digiseis-FLX system presents advantages over other TZ equipment, called bay cable. Bay cable consists of a 1/3-in. diameter instrumented cable, two to three miles long, that lies on the sea bottom. 

The cable can shift with currents, and can be damaged by boat propellers and sharp coral. While radiotelemetry avoids these problems, the added flexibility creates a new problem, synchronization: each unit must record at exactly the same time. The Digiseis-FLX system uses a patented synchronization method, achieving an accuracy significantly higher than other radiotelemetry systems. 

Another innovation that contributes to the speed of the survey is the method with which the source explosives and the hydrophones are emplaced. The technique- ramming- is like using a hypodermic needle to inject a source or receiver into the earth. Ramming sources in soft transition zone cuts down on the time required to drill source holes. On land, drilling crews typically drill 100 to 180-ft [30 to 55 m] deep shot holes in advance of the acquisition crew. Equivalent results are obtained with 40 to 50 ft deep ram holes. 

Ramming not only takes less time, but it also costs less. Deep holes cost about $300 per hole to drill, while ramming cost about $75 per hole. Ramming hydrophones to a uniform depth of 20 ft [ 6 m] below sea level results in better receiver coupling and higher quality data. The main limitation of ramming is the restriction to unconsolidated earth.

Not all the North Freshwater Bayou turnaround speed came from fast acquisition. Geometry verification- much like navigation data processing in the marine environment- carried out in the field, cut weeks off the normal processing time. Geometry verification, a feature of the Voyager mobile data processing system, checks that the source and receiver positions attributed to every shot record are correct. Usually this is checked back at the office after acquisition has been completed and the crew has left, but fixing errors after the fact is time-consuming. In some cases, entire land surveys have had to be reshot- a turnaround nightmare.

One error typically encountered in geometry verification is a mistake in the identifcation of shot-point location. This can occur when the source, say a vibrating truck (vibro for short) is at the wrong location, can't get to the right location, or if the location is miss-surveyed. It can also occur if receiver locations are missurveyed, or if the wrong receivers are active.

These mistakes can be detected quickly by applying some simple processing at the base camp, after the day acquisition. The process is called linear moveout , or LMO. LMO compares arrival times recorded for a given source-receiver geometry to those expected for the same geometry, assuming a constant velocity subsurface. If the source and receivers are in the right places, the LMO process yields seismic traces with first arrivals aligned in time. Any other pattern of first arrivals indicates a mistakes in the source-receiver geometry. 

This technique was used in the Unocal survey to quickly verify geometry in the field. Catching errors with the crew still on site permits corrective action. Shot and receiver locations can be resurveyed if necessary to revise the location data base. Without this field verification, errors may be detected weeks or months later. Then, processing specialists would have to test several possible geometries in hopes of discovering what really happened, spending time and adding uncertainty. Verifying the geometry in the field saves up to four weeks in the office. 

With much of the time-consuming work out of the way, the computing center proceeded with the rapid disk-to-disk processing on a Sun SPARCstation 20. The fully processed 3D cube was ready three weeks after acquisition, in time for interpreters to use. 

Interpretation of the seismic volume signaled drillers that their target would be productive. Unocal interpreters were able to use the seismic data to confirm the quality of their next well location and plan at least one additional deep well at greater than 20,000 ft [6090 m].

Reducing Turnaround on Land

Three-dimensional surveys on land encounter many of the same difficulties as in transition zones, with the added problems of access, topography and extreme temperatures. All of these make for longer acquisition campaigns and more difficult processing.  Under fair marine conditions, multielement acquisition can collect more than 75 km square per day. Under extreme land conditions, such as -40 degree C arctic surveys, acquisition may proceed at less than 1 km square per day. Land surveys of 1500 km square have taken up to 4 1/2 years for acquisition. 

In land surveys more than other types, presurvey planning is the key to minimizing turnaround. Time spent planning and designing is more than compensated by time saved acquiring data. With a given set of equipment, say a certain number of geophones and people, one plan might achieve 150 to 200 shots a day, while suboptimal plan with different shot and receiver line spacing may collect only 100 shots a day.

The most time-consuming tasks in acquisition - be they laying out receivers, drilling shot holes, repairing damaged cables or advancing to the next vibro location - must be identified and minimized to reduce turnaround. In the following examples of 3D land surveys in Texas, such bottlenecks were identified during presurvey planning and circumvented in novel ways. 

Rough Terrain Turnaround

The Val Verde basin in Texas, USA is at the edge of the Sierra Madre mountains that extend north from Mexico. The basin is a hot play for gas, with some wells in the region producing more than 7 MMcf/D. The terrain is extremely rough, with steep-edged mesas and incised canyons. Several 3D surveys in the area have contributed to the continuous improvement of field operating procedures.

In one case, Conoco joined forces with Hunt Oil to acquire the Geaslin survey in the summer of 1994. Both companies had a short fuse: they had to evaluate their leases and make decisions for an early 1995 drill date. The survey design specified the number and location of shot points, but the short turnaround and high cost ruled out dynamite as a source, because too much time would be taken to drill shot holes. 

Vibro sources were available- four vibrating trucks at 12.5-m spacing constitute one source - but the terrain presented mind-boggling logistics: in some cases it would take four hours for a vibro trip up and down a mesa.  

The solution was to use two sets of buggy vibros, or eight in all, similar to a dual-source marine survey. While one set was shaking in the valley , the other set would work its way up a mesa. Similar dual-source vibro operations have been extremely successful in desert areas, such as Egypt and Oman, where there are no obstructions. In this case they allowed acquisition of 60 sq miles [153 km square] in 65 days.

As in all land jobs, darkness presents too many hazards, so the crew operates only during daylight hours. Evenings were well spent, though, running geometry verification on the day's acquired data. One of the goals of the next shift was to have that day's geometry checked and attached to the seismic traces, usually by midnight. That way, geometry problems could be fixed the next day, before the receivers were moved. 

Processing the data from the Geaslin survey proved to be a great challenge. Val Verde basin is notorous for bad data. High velocity carbonates near the surface deflect much of the source energy away from deeper layers; receiver and source coupling to the surface varies with location; and the rugged relief introduces high residual statics- differences in seismic travel time through surface topography. After four months of testing and processing, including 3D DMO and migration, the processing was complete. The next step is preparation, in preparation for a possible 1995 drill date. 

In the nearby Brown Basset survey for Mobil, acquisition time was further shortened by the use of helicopters to move cables, recording boxes and geophones up and down the mesa and canyon walls. Three hundred "helibags" - net bags for transporting material- helped the crew complete the 153 km square acquisition in significantly less time than usual. 

What's Coming to Land

Keeping track of all the information pertinent to a land survey is often the most time consuming job, and steps are being taken to shorten it and make fuller use of all the information available. 

The Olympus-IMS information management system, now in use by Geco-Prakla in Germany, is designed to do just that.

The Olympus-IMS system colocates in a single data base the many types of data that must be handled in a land survey. Previously, every type of data had its own data base: the planned survey layout, the actual surveyed receiver and source point locations, shot hole drilling data, shooting schedule data and the recorded seismic trace data were handled by different software. The new integrated system minimizes the number of data handling steps, reducing errors and improving turnaround. The system will also link directly with processing software to allow field processing for geometry verification and further processing steps. 

Further improvements in land turnaround will come from improvements in hardware and communication. In the most adverse conditions, a good crew may spend as little as two to three hours shooting out of ten spent in the field. In these circumstances,a small amount of time spent trouble-shooting equipment faults can have a considerable impact on turnaround. Geco-Prakla engineers are developing more reliable hardware, to reduce the amount of time spent looking for and repairing flaws in geophones, cables and connectors. Today, each receiver point marked on a map consists of up to 72 individual geophones, whose signals are combined to yield a less noisy signal at a central location, or source point. Up to 140,000 geophones will have to be repeatedly picked up, put down and maintained in the course of a 3D survey. Efforts are also underway to find new ways to acquire the same amount and quality of data with fewer receivers, cutting survey time. 

Improved communications will also cut turnaround time. Increased use of GPS is decreasing the time spent  surveying positions for land source and receiver points. Surveying with GPS is faster and easier to check than traditional theodolitic surveying, and leaves less room for human error.  Placing GPS units on vibro sources helps keep track of actual source locations and reduces location error.

For arctic land surveys, snow streamers have been developed in collaboration with Norsk Hydro as substitutes for hand-placed geophones in an effort to increase acquisition efficiency. Geco-Prakla engineers have tested snow streamers in six programs, acquiring 1200 km of 2D data. Efforts are also underway to minimize environmental impact, which in arctic environments must be included as part of turnaround- a single drop of oil spilled must be recovered before the crew moves.

Connecting land crews via satellite to SINet, the Schlumberger Information Network, will give better day-to-day contact with office bases, speeding equipment and supply requests and allowing interaction with processing centers. 

Moving more processing to the field will further reduce turnaround for both land and transition zone surveys. Parameter testing, noise attenuation and velocity picking can be done with today's field processing tools. But full concurrent processing, as performed in marine surveys, is still a dream for land. 

Land acquisition, more so than marine , is a three-dimensional problem: sources are not aligned with receiver lines, and more time is needed to acquire enough seismic traces to process one part of the 3D volume. 

At best, processing through to stacking could lag acquisition by a few weeks, but the difficult task of computing residual statics before stacking cannot begin until all data are in. Advances may come from taking a new view of 3D land surveys- planning, acquiring and processing with a truly three-dimensional view- rather than simply repeating a series of two-dimensional snapshots.

The Role of Integrated Services in Reducing Turnaround

Marine, TZ and land 3D surveys are sure to find further turnaround improvement in the common ground of integrated services. In an integrated-service survey, planning, acquisition, processing and project management are delivered by one service company. Traditionally, the oil company plans the survey, then one contractor acquires the data and another processes it. Time is wasted transferring data and responsibility between parties. 

Geco-Prakla has developed an integrated service for 3D surveys called TQ3D- Total Quality 3D. Larger in area than most surveys, TQ3D projects can cover leased and open blocks. A TQ3D projects may be operated from 100% nonexclusive, or anywhere in between. Data acquired on proprietary basis become the property of the operator.