Analysis of historical drilling data in the Delaware Basin revealed stick-slip was being initiated by the rig control system. It was determined that a weight-on-bit (WOB) road map with calibrated range values delivered near-maximum rate of penetration (ROP) and reduced stick-slip. This was achieved by simplifying the auto-driller's parameter limits and avoiding differential pressure control. Details of the statistical analysis process and results from field trials is presented and compared to historical performance.
The road map was developed using data from top performing offset wells. The standard deviation of the auto-driller's active control limiters was cross-plotted against the standard deviation of the ROP. Intervals in which the differential pressure was the primary control or the ROP range was excessive displayed a high standard deviation, indicating unstable control behavior. Data from the non-dysfunctional areas determined the WOB and ROP ranges to be targeted through an interval. Use of these range limits steadied the application of WOB and reduced the need to control the auto-driller via differential pressure.
Wells using the parameter road map were compared to high-performing offsets. The comparative analysis focused on ROP, mechanical specific energy (MSE), downhole accelerations, and bit damage. Performance in formations known to cause dysfunction are highlighted. Benefits have been observed in the rotary steerable control collar RPM data. Depth-of-cut (DOC) through the Brushy Canyon was improved by use of the road map. Traditional auto-driller limiters (torque and differential pressure) were avoided due to the limits of the drilling system embedded within the road map's setpoints. Data are presented showing that differential pressure control can result in stick-slip. This dysfunction is avoidable with the use of a road map employing accurate range values for WOB and ROP to control the auto-driller.
Improved auto-driller range management addressed a specific source of dysfunction and positively impacted performance at the bit. The visual road map conveyed WOB and ROP guidance directly to the driller, which accelerated the rig's learning curve. When combined, the product of these data-driven concepts increased bit life and ROP.
Organic-rich mudrocks (ORM) from the Brushy Canyon Formation in west Texas were deposited in the Middle Permian during the Guadalupian epoch in the Delaware Basin. Brushy Canyon ORM were examined for Re-Os isotope systematics with a goal of constraining their depositional age, the 187Os/188Os value of seawater at their time of deposition, and to examine how Re and Os partition into organic material in ORM. For these samples, Rock-Eval pyrolysis data (HI: 228-393 mg/g; OI: 16-51 mg/g) indicates predominantly Type II marine kerogen with minor contributions of Type III terrestrial organic matter. Rhenium and osmium abundances correlate positively with HI, and negatively with OI, which are proxies for organic matter type and degree of preservation. These data are consistent with previous work that indicates Re and Os abundances are controlled by the availability of chelating sites in the kerogen. Brushy Canyon Formation samples have (total organic carbon) TOC values between 0.97 and 4.04% and show a strong positive correlation with both Re and Os abundances, consistent with correlations between these parameters in other ORM suites. The positive slopes in these correlations are distinct between marine (higher slopes) and non-marine (lower slopes) lacustrine environments of deposition. The Brushy Canyon’s steep slopes are consistent with marine deposition of its organic matter and an open-ocean non-restricted setting. The relationship to other Re-Os and TOC data sets appears to be a function of the restrictivity of marine conditions, and associated variations in reducing conditions during ORM accumulation of the Delaware Basin compared with more restricted lacustrine basins with local drawdown of Re and Os.
The Re-Os isotope systematics of ORM from the Brushy Canyon Formation yields a Model 1 age of 261.3 ± 5.3 Ma (2.0% age uncertainty; MSWD = 0.82). Within the uncertainty, this agrees with the expected Guadalupian age for this formation. This Re-Os age represents the first direct, absolute age for Guadalupian organic matter in the Delaware Basin. The initial (187Os/188Os)i = 0.50 ± 0.06 obtained by isochron regression represents the 187Os/188Os of seawater at this time. This value is significantly less radiogenic than modern day seawater (~1.06). The lower 187Os/188Os of Guadalupian seawater recorded is likely caused by a decrease in the relative flux of radiogenic Os from continental weathering due to a number of local and global climatic and tectonic changes that were occurring during this time.
Fluid volumes in fracturing treatments have increased substantially, while water supply has become more of a public concern. Rather than paying to treat and dispose of produced and flowback water, operators would like to reuse it in subsequent stimulation treatments. Produced water with high total dissolved solids (TDS) and high divalent cation content poses extreme challenges for emulsion friction reducers because cations hinder the inversion of friction reducers and cause loss of efficiency of friction reduction. Treating produced water to the quality suitable for conventional fracturing fluids is time-consuming and often cost-prohibitive.
A salt-tolerant friction reducer was developed to address the challenges of high-TDS produced water. In a produced water sample with high TDS and high total hardness, the new polymer hydrates within 10 seconds and gives a friction reduction profile similar to that of current inverse-emulsion friction reducers in fresh water. The fluid is compatible with other common stimulation additives such as scale inhibitors, biocides, clay stabilizers, surfactants, and breakers.
The paper discusses field test results and production response from slickwater fracturing operation in Delaware basin with produced water containing more than 250,000 ppm TDS and 60,000 ppm total hardness. Head-to-head comparison with conventional crosslinked fluids and friction reducers under field conditions showed significant oil and gas production improvement resulting from increased fracture complexity by pumping low viscosity fluids at higher pumping rate in extremely high-TDS produced water. It provides the oilfield industry a cost-effective solution of reducing produced water disposal and fresh water demands, thereby ultimately improving environmental and economic impacts of well operations.
Large quantities of high-TDS produced water (typically greater than 250,000 mg/L) are produced from existing oil and gas wells from Delaware basin. In 2011, more than 164 million bbl of produced water were produced and the reinjection cost into disposal wells alone was estimated at an average cost of USD 0.75 to USD 1.00 per bbl (LeBas et al. 2013). Meanwhile, the fluid volumes in slickwater fracturing treatments have increased substantially. Rather than paying to treat and dispose of produced and flowback water, operators would like to reuse it in stimulation treatments. For typical slickwater operation, friction reducers (FRs) are normally added to the water-based fracturing fluids “on the fly” as water-in-oil emulsions to reduce friction pressures. When FRs are pumped into water, the emulsion inverts to oil-in-water emulsion, releasing the polymer, which swells (hydrates). The hydrated, disentangled polymer molecules then work as a FR. This process is also known as “inversion”. Aften (2010) summaried three key factors determining the potential performance of these inverse-emulsion FRs: 1) solubility and flexibility of polymer in various aqueous phases; 2) the polymer’s ability to instanteously destabilize the inverse emulsion into stimulation fluids, e.g. produced or flowback water; and 3) the polymer’s compatibility with other fracturing additives, such as breakers, scale inhibitors, biocides, surfactants, and effectiveness under field conditions such as extremely low temperature. High total dissolved solids (TDS) and high divalent cation content in the Delaware basin produced water poses great challenges for hydration of emulsion FRs because cations hinder the inversion of FRs and cause loss of efficiency of friction reduction to below 30%. Treating produced water to the quality suitable for conventional fracturing fluids is time-consuming and often cost-prohibitive.
The Permian was an unusual time in the Earth's past, a time of continental accretion, falling sea level, and of global cooling. Basins formed at this time hold some of the most prolific petroleum systems in the world, are well studied, yet still hold much mystery with respect to their relationship between tectonic evolution, sedimentary fill, thermal maturities, and remaining exploration potential. One such important Permian basin is that of the deep Delaware Basin of southeastern New Mexico and west Texas U.S.A. Tectonic subsidence analysis of 11 boreholes reveal best fit kinetic maturities which require one major tectonic extension event from ~268 Ma to ~251 Ma (betas ~1.25 to ~1.53) and shortening from 80Ma to 65Ma (beta ~0.855). Principal source rocks are the underlying Devonian Woodford, Carboniferous Barnett, Permian Wolfcamp, Bone Spring and Delaware Mountain Group (DMG) formations. Modeling shows that the DMG and Bone Spring Formations are presently within the oil window whereas the Woodford and Barnett formations are below the oil window. The DMG began entering early mature oil phase in late Permian. Woodford and Barnett formation began entering the early mature oil phase in the late Pennsylvanian. The Bell Canyon formation is within the main oil window in the deeper part of Delaware Basin (northeast and eastern part of Delaware Basin) whereas the Brushy Canyon formation is within the main oil window in the northern part of the Delaware Basin. Major migration pathways in the Delaware Basin are SE to NW and SW to NE. The critical moment for the accumulation of liquids in the DMG and Bone Spring is Late Permian, around 265Ma -261Ma. Knowledge of the thermal maturity evolution of the Delaware Basin provides important constraints upon determining optimal exploration programs for exploiting liquids and gases either conventionally or unconventionally in these Permian strata.
Assessing reservoir connectivity and permeability heterogeneity is essential for predicting reservoir performance. As reservoirs are three-dimensional entities, there is little value in trying to predict reservoir connectivity based on two-dimensional data such as geological sections or maps. A new method for seismic volumetric visualization, complemented with outcrop analog data, was used for assessing reservoir connectivity and permeability heterogeneity of the deep-water reservoirs of Marlim Sul field, Campos Basin, Brazil.
The method consists of combining reflectivity and impedance seismic volumes. For the reservoir target zone, reflectivity was used as top drape covering the whole area, with color contrasts discriminating reservoirs and non-reservoirs, whereas in the impedance volume a cutoff value was used to show only the reservoirs. Such volumetric visualization technique permits the better identification of architectural elements and the better understanding of the evolution of the depositional system. However, some limitations still remain. Before building a reservoir model, it is necessary to assess (1) the internal permeability heterogeneity of the different architectural elements, and (2) the petrophysical nature of the boundaries among the different elements. This was performed by comparing geometries and facies observed in subsurface with geometries and facies documented in outcrop analogs. The main controls on connectivity and permeability heterogeneity in deep-water reservoirs are permeability barriers and baffles, such as hemipelagic shales and marls, turbiditic drapes, debris-flow deposits, shale-clast breccia and cemented zones. Such features present a complex and varied distribution. Barrier and baffle 3D maps of the different architectural elements and of the limits among them obtained in representative outcrops were used to complement seismic information.
The integration of seismic volumetric visualization with outcrop analog data, calibrated by well information and tested again production data, proved to be useful for improving reservoir models.
Clawson, Steven (iReservoir.com) | Meng, Hai-Zui (iReservoir.com) | Sonnenfeld, Mark (iReservoir.com) | Uland, Mike (iReservoir.com) | Atan, Safian (Colorado School of Mines) | Batzle, Mike (Colorado School of Mines) | Gardner, Mike (Colorado School of Mines) | Uman, M. Syafiul (Colorado School of Mines)
Incomplete or sparse information contributes to high levels of risk for oil exploration and development. To more accurately and consistently predict drilling risk, a degree of automation of data analysis may be helpful. "expert systems" developed and used in several disciplines and industries, have demonstrated beneficial results in modeling the decision making process of human experts. A state-of-the-art "expert" exploration tool using computerized multidisciplinary databases, expert developed "rules", and regional data maps -- generated using artificial neural networks, has been developed.
The system employs a web interface for users to select prospect(s) of interest and to allow data review or addition, and includes security to maintain the sanctity of proprietary information. Two types of rules are applied to the data. Heuristic rules are generated directly from engineering, geophysical and geological databases. Expert rules are developed through interviews with successful prospectors. Rules are applied in four categories: Regional Indications, Trap Assessment, Formation Assessment, and Oil Price. Some users may elect to not factor in certain aspects, or to use their own values.
Each of the sub systems assigns a numerical score based on the answers to individual "expert" questions. Results are then combined to form an overall risk assessment associated with the selected prospect(s). These scores can be derived from "crisp" mathematical computations, "fuzzy" analysis, or a combination of the two.
This expert system can help companies of all sizes, to more efficiently evaluate prospect quality, and thus more rapidly eliminate poor prospects and generate new production from favorable prospects. The initial system has been initially tuned for the Brushy Canyon formation, Delaware basin, New Mexico.
Clawson, Steven (iReservoir.com) | Meng, Hai-Zui (iReservoir.com) | Sonnenfeld, Mark (iReservoir.com) | Uland, Mike (iReservoir.com) | Batzle, Mike (Colorado School of Mines) | Atan, Safian (Colorado School of Mines) | Gardner, Mike (Colorado School of Mines) | Uman, M. Syafiul (Colorado School of Mines)
Balch, R.S. (New Mexico Petroleum Recovery Research Center) | Hart, D.M. (Sandia National Lab) | Weiss, W.W. (New Mexico Petroleum Recovery Research Center) | Broadhead, R.F. (New Mexico Bureau of Geology and Mineral Resources.)
Incomplete or sparse information introduces a high level of risk for oil exploration and development projects. "Expert" systems developed and used in several disciplines and industries have demonstrated beneficial results in modeling the decision making process of knowledgeable experts. A state-of-the-art exploration "expert" tool using a computerized data base and computer maps generated by neural networks, is being developed using fuzzy logic, a relatively new mathematical treatment of imprecise or non-explicit parameters.
Analysis to date includes generation of regional scale maps of aeromagnetic, gravity, structure, thickness, and production data for the target Brushy Canyon Formation in the Delaware Basin, New Mexico. For each regional scale map, data attributes were also computed to look for more subtle trends. These attributes include directional first and second derivatives, dip azimuth and magnitude, and azimuth and magnitude of curvature. These data were mapped and gridded to a 40 acre spacing, the current well spacing for Delaware pools in New Mexico, and compared to average monthly production in the first year for Delaware Brushy Canyon wells. The geophysical and geologic data covers 60478 bins (3780 square miles), of which 2434 of these bins have oil, gas and water production data. Using a new fuzzy ranking tool each data attribute was ranked for its ability to predict production potential at these well locations. The highest ranked attributes are gravity dip-azimuth, second latitude derivative of thickness, longitude derivative of gravity, and longitude derivative of structure. These attributes are being used to generate a production potential map for the Delaware basin, using neural networks and expert systems, at the scale of 40 acres. Such a map would be a useful tool for evaluating the potential of infill, step out, and wildcat wells in the Delaware basin, both at reservoir and regional scales.
Expert systems are computer programs that are designed to make decisions similar to the manner in which a human expert would. In the past expert systems have been primarily restricted to medical and industrial applications, but with DOE support an expert system to prospect for oil is now being developed to automate and accelerate prospect development for the Brushy Canyon formation in the Delaware basin. Expert systems operate by developing rule sets that can be used to answer questions related to the problem at hand, in this case prospect evaluation. Since prospect generation data often contains non-crisp data, such as "low porosity" or "high on structure", the expert system will necessarily allow fuzzy inputs. The approach taken is to accumulate all available public domain data and incorporate them into online databases, which can be accessed by the expert system. A primary goal was to develop a map of production potential based on available regional data from which the expert system could add or detract to each prospects estimate of risk. This paper discusses the development of this production potential map.