Recent advances in downhole tools have helped unravel subsurface mysteries whose solutions that oil companies could only guess at just a few short years ago -- and one of those important advances has been the latest generation of nuclear magnetic resonance wireline tools.
This recently developed technology has become an important part of many companies' operations.
How important? Case studies from wells in the Gulf of Mexico and on the Gulf Coast illustrate just what NMR can add to the overall downhole picture.
First, some general reminders about NMR.
NMR tools allow explorationists to acquire accurate values for formation permeability, movable and bound-fluid volumes, irreducible water saturation and formation fluid type under a wide range of borehole conditions.
These petrophysical formation parameters were previously only attainable from expensive conventional cores or an extensive sidewall coring program on wireline, according to a group of scientists with Texaco Exploration and Production Inc. and Schlumberger Oilfield Services.
Roy Guest, Marcel Di Giovanni, Stacy Smith and Otis Walter with Texaco joined Jon Musselman, Tom Pickens and Steve Crary of Schlumberger in presenting the paper "Case Studies of Nuclear Magnetic Resonance, Texas and Louisiana Gulf Coast Area" at the 1998 AAPG annual meeting.
Nuclear magnetic resonance techniques can supplement traditional logging measurements to evaluate diverse reservoir types, the group concluded in its paper -- and they used three case studies from offshore Louisiana and east Texas to demonstrate how NMR data can be integrated with other information to provide cost-effective formation analysis, resulting in successful identification and enhanced production of hydrocarbons in a variety of reservoirs.
Density, neutron and induction logs traditionally have been used to evaluate sandstone reservoirs in the Gulf Coast area. The combination of these measurements has proved cost effective for determining formation lithology, porosity and water saturation, which are then used for predicting the interval's producibility.
However, in many zones accurate producibility prediction is difficult, the authors said. For example, prediction may be too pessimistic in zones with high irreducible water caused by very fine-grained rock texture or thin beds. In other cases, the wellbore environment creates difficulties -- oil-based mud, in particular, can make interpretation difficult by invading deeply into the formation and masking traditional log response.
NMR measurements respond to the formation's porosity and pore size, they said, and can help in these difficult circumstances by providing additional information on the producibility of the reservoir.
Case Study 1
Texaco realized the value of adding magnetic resonance and formation micro imaging to the traditional suite of logging tools on a recent offshore Louisiana exploration well.
The combination of data from NMR and microresistivity images allowed Texaco to obtain accurate reserve figures for a submarine canyon-fill play in the offshore Gulf of Mexico -- and these tools helped to reduce the need for large numbers of sidewall cores in future development wells.
Texaco's prospect had been partially tested by two prior leaseholders. Several of the reservoirs in the combination structural-stratigraphic traps in the play had given potential low-resistivity pay responses on conventional wireline logs in the top of a thick, highly laminated, sandy interval.
After evaluating these prior data, the Texaco team was still uncertain about the volume of hydrocarbons and the nature of the fluid contact, which made estimating reserves difficult.
One fault segment, in particular, had been evaluated with only a compensated dual resistivity log acquired while drilling. Core and formation test data had not been acquired.
Based on the data available, however, the exploration team developed a scenario that predicted an irregular oil/water contact in the thick laminated sand.
To test this interpretation, Texaco explorationists proposed a well designed to penetrate the largest reservoir segment about 100 feet structurally low to the highest known water contact in an existing up-dip well. The well's surface location was chosen to lie central to any future development in the play, but the wellbore itself would be highly deviated, compounding formation evaluation difficulties.
The prospect's economic success was critically sensitive to adequate reserve volumes, so sufficient formation evaluation data were needed to accurately model the potential reservoir, they said. The formation analysis package incorporated resistivity, density and neutron measurements acquired while drilling with wireline microresistivity images and NMR data.
Sidewall core measurements were acquired using drillpipe-conveyed wireline logging techniques for calibration of the porosity and permeability values generated from the logging data.
The volumetric analysis computed from the logs identified the lowest known oil and highest known water levels at exactly the same depths, they said. Permeabilities correlated closely to the sidewall core-derived values, and highly porous and permeable zones could be distinguished from silty, less permeable zones.
"The effective porosity and permeability were then used with confidence by the exploration team over the entire reservoir interval to complete their volumetric estimate," the authors reported.
The NMR data integration led to a successful completion in this well. The use of logging while drilling and the acquisition of NMR data in "bound-fluid mode" at a relatively fast 1,200 feet per hour helped to reduce the cost of the evaluation.
This logging suite costs less to acquire than conventional coring, they said, and provided accurate measurements of formation permeability, movable and bound-fluid volumes, fluid types and images of facies architecture across the entire reservoir interface.
These data were key to the estimation of the prospect's recoverable reserves and the ultimate design of a field development plan.
Case Study 2
A second case study came from a very different Texaco well offshore Louisiana.
In this well the Lower Pliocene sands were found in a stacked sequence of mid-fan channel and levee complexes. This depositional environment is characterized by facies ranging from massively bedded channel sands to inch-scale laminations in the overbank deposits.
Traditional log analysis is difficult in these very thinly bedded sands, the authors said. The vertical resolution of these measurements is such that they totally respond only to the thickest zones.
According to the authors, the unknown sand quality would have made it difficult to justify a test of this interval, but the addition of the NMR data suggested that the interval may have sufficient permeability to warrant a test.
The best interpretation of this low-contrast interval was achieved by combining high-resolution microresistivity imaging with NMR permeability and fluid analysis, since the microresistivity images indicated thin laminations -- which in turn suggests that the permeability is even greater than the average values computed by combining density, neutron, resistivity and magnetic resonance data.
Texaco's well was completed and tested more than 1,000 barrels of oil a day.
Bottom line: The successful test of this laminated interval opens a large potential play for development in an interval that heretofore was considered unproductive.
Case Study 3
Texaco and Schlumberger described a third case study in the Lower Cretaceous Travis Peak Formation in east Texas.
Sandstones of this formation long have been considered a difficult log interpretation problem -- and integrating NMR logs with the other logs has added greatly to success, the authors said.
These sandstones typically produce gas from porosity ranges of 8-15 percent, and permeabilities usually less than one millidarcy.
The major petrophysical challenge in this formation is predicting hydrocarbon versus water production from zones exhibiting similar porosity and resistivity, they reported. Predicting water production is especially important because typical completions are hydraulically fractured in multiple stages and the ability to derive bound fluid volumes and estimate permeability from NMR logging enables the petrophysicist to more accurately predict which intervals will produce water.
Texaco's field in east Texas had produced from a deeper horizon, and the Travis Peak had not previously been targeted. The firm used Schlumberger's PLATFORM EXPRESS™ (trademark of Schlumberger) and a combinable magnetic resonance tool combination to gather all the needed data in a single descent.
When the logs were reviewed, an interval was noted that had a strong gas show on the mud log, but a resistivity of only 0.8 ohm-m. Water saturations computed using traditional log analysis techniques were very high, but the NMR log identified this interval as having high capillary-bound water, suggesting that the zone had sufficient permeability to produce without hydraulic fracturing.
The zone was completed for 500 thousand cubic feet of gas, 50 barrels of oil and 100 barrels of water per day with no treatment necessary.
NMR logs also proved effective in optimizing completions in this area. In a second interval, for example, NMR indicated potential pay in a low-permeability interval. Field experience had shown that hydraulic fracturing was necessary for a successful completion in such intervals.
However, there was a zone that the analysis indicated would be water productive 40 feet below the completion interval.
The solution was a completion designed to minimize fracture growth into the water productive interval, resulting in production of 2.2 million cubic feet of gas and 150 barrels of oil a day -- and no water.
Texaco now uses NMR technology as an integral part of its formation package, the authors reported.
Indeed, the firm has found it "a valuable tool" for predicting the production potential of an exploration well, they added -- a critical step, for example, when allocating resources for a new platform or subsea development project.
Explorationists today are faced with the dilemma of how to both reduce costs and acquire adequate formation evaluation information to estimate a prospect's recoverable reserves, they said.
Their conclusion: Both objectives can be achieved by incorporating magnetic resonance logging into the evaluation program.