Petrophysical Parameters that Govern Hydrocarbon Production From a Low-Permeability Carbonate Formation at the Wattenberg Field in the Denver-Julesburg Basin

2007 ◽  
Author(s):  
Yuanhai Yang ◽  
Wally G. O'Connell ◽  
Thomas J. Birmingham
Keyword(s):  
Low Permeability ◽  
Hydrocarbon Production ◽  
Wattenberg Field ◽  
Petrophysical Parameters ◽  
Carbonate Formation

Economical Feasibility Study of Abandoned Oilfields Utilizing Smart Modeling Approach: Case Study

2009 ◽  
Author(s):  
Hadi Belhaj ◽  
M. S. Zaman ◽  
Terry Lay
Keyword(s):  
Oil And Gas ◽  
Assessment Tool ◽  
Oil Prices ◽  
Horizontal Wells ◽  
Production Performance ◽  
Advanced Technology ◽  
Co2 Injection ◽  
Low Permeability ◽  
Well Testing ◽  
Carbonate Formation

Petrel, Eclipse and Monte Carlo are three simulators often used separately to evaluate reservoir structure, production performance and economics/planning/risk analysis respectively. Integration of the three packages provides a very comprehensive and efficient assessment tool for oilfields or blocks with limited data by avoiding incompatibility, data transformation and interface problems. Many oil and gas fields that have been discovered in the past and abandoned as a high risk venture have become of prime interest to numerous smart investors taking advantage of high oil prices and advanced technology. Some of these discoveries have exhibited reasonable hydrocarbon accumulations through seismic surveys, actual drilling and initial well-testing. Their development has previously been hindered by uncertainty and by low oil prices. The ALT Field, North Africa, is a typical example. Only nine vertical wells were drilled in the ALT Field during the 1960’s including three dry holes. Low production from three zones of Chalk Carbonate formation with moderate porosity and very low permeability (less than 1 md), meant the field has been abandoned for over three decades. Recently, with oil prices flourishing, the field has caught the eye of many potential developers. By utilizing the three-simulator approach, the ALT field has been verified as a potential producer of commercial oil. Two scenarios, single-pool and two-pool, have been established for describing the field structure, both are economically feasible, with more profitability foreseen from the single-pool scenario. The two-pool scenario demonstrated the field contains 885MMblls OIIP with estimated total reserves of 310MMbbls of oil using waterflooding alone and an additional 89MMbbls using CO2 injection. The existing six vertical producers are recommended to be used for injection, while a pattern of horizontal wells are suggested to be drilled and used as producers. The horizontal wells are favored over vertical ones to overcome the very low permeability situation. Development of the ALT Field is ongoing based upon the findings of this study. The idea of the three-simulator approach has proven workable, thus has potential to be used in similar cases once minor technical software problems are resolved.

Image-Based Petrophysical Parameters: CT Imaging of Chalk Cuttings and Experimental Comparisons by Plug-Size Upscaling

SPE Journal ◽  
2016 ◽  
Vol 22 (01) ◽  
pp. 41-52 ◽  
Author(s):  
Jakob Noe-Nygaard ◽  
Finn Engstrøm ◽  
Theis I. Sølling ◽  
Sven Roth
Keyword(s):  
Pore Space ◽  
Complex Structure ◽  
Ct Imaging ◽  
Low Permeability ◽  
Micro Ct ◽  
Two Phase ◽  
Petrophysical Parameters ◽  
Root Cause ◽  
Sufficient Detail ◽  
Experimental Comparisons

Summary In the present study, the focus is on two 2- to 3-mm cuttings-scale reservoir chalk samples chosen such that the resolution of the pore space is challenging the state of the art and the permeability differs by a factor of four. We compare the petrophysical parameters that are derived from nano-computed-tomography (nano-CT) images of trim sections and cuttings. Moreover, the trim-section results are upscaled to trim size to form the basis of an additional comparison. The results are also benchmarked against conventional core analysis (CCAL) results on trim-size samples. The comparison shows that petrophysical parameters from CT imaging agree reasonably well with those determined experimentally. The upscaled results show some discrepancy with the nano-CT results, particularly in the case of the low-permeability plug. This is probably because of the challenge in finding a representative subvolume. For the cuttings, the differences are significant for the low-permeability plug. For the two-phase-flow data, the predicted relative permeability endpoints differ significantly. The root cause of this again is attributed to the more-complex structure of the pore network in the low-permeability carbonate. The experiment was also run directly from the micro-CT results on a cutting measured on an in-house instrument; the results clearly show that micro-CT measurements on chalk do not capture the pore space with sufficient detail to be predictive. Overall, with the appropriate resolution, the present study shows that it is indeed feasible to obtain petrophysical parameters from imaging experiments on cuttings.

scholarly journals Chemostratigraphy of the Upper Jurassic (Oxfordian) Smackover Formation for Little Cedar Creek and Brooklyn Fields, Alabama

2019 ◽  
Author(s):  
Rian Engle ◽  
Lance D. Yarbrough ◽  
Greg Easson
Keyword(s):  
Upper Jurassic ◽  
Hydrocarbon Production ◽  
Elemental Ratios ◽  
Cedar Creek ◽  
Smackover Formation ◽  
Carbonate Formation ◽  
Major Producer ◽  
Well Data ◽  
Paleozoic Rocks ◽  
Handheld Scanner

The Upper Jurassic (Oxfordian Age) Smackover Formation is a significant source for hydrocarbon production in southwest Alabama. Brooklyn Field is in southeast Conecuh County, Alabama and has been a major producer of oil and natural gas for the state. The Smackover is a carbonate formation that is divided into seven distinct lithofacies. In southwest Alabama, the Smackover Formation is heavily influenced by paleotopography from the underlying Paleozoic rocks of the Appalachian system. The goal of this study is to determine elemental ratios in rock core within the Smackover Formation using a X-ray fluorescence (XRF) handheld scanner, to correlate between lithofacies in the Smackover Formation and elementally characterize the upper oolitic grainstone reservoir and the lower thrombolite boundstone. Eight wells were used for the study within Brooklyn Field and Little Cedar Creek fields. Cores from the eight wells were scanned on six-inch intervals. Chemical logs were produced to show elemental weights in relation to depth and lithofacies. Well data collected for chemical signatures within producing zones were correlated to reservoir lithofacies and porosity. Aluminum, silicon, calcium, titanium, and iron were the most significant (>95% confidence level) predictors of porosity and is related to the depositional environment and subsequent diageneses of the strata. XRF data suggests relative enrichments in iron, titanium, and potassium may be related to deposition in relatively restricted marine waters.

Acid Fracturing of Low Permeability Carbonate Formation Lessons Learned

2018 ◽  
Author(s):  
M. Rafie ◽  
F. M. AlOtaibi ◽  
M. N. Al-Dahlan ◽  
S. H. Suwadi
Keyword(s):  
Lessons Learned ◽  
Low Permeability ◽  
Acid Fracturing ◽  
Carbonate Formation

scholarly journals Evaluation of Petrophysical Parameters of Reservoir Sand Wells in Uzot-Field, Onshore Niger Delta Basin, Nigeria

2021 ◽  
Vol 25 (2) ◽  
pp. 157-171
Author(s):  
UC Omoja ◽  
T.N. Obiekezie
Keyword(s):  
Niger Delta ◽  
Gamma Ray ◽  
Depth Range ◽  
High Hydrocarbon ◽  
Hydrocarbon Production ◽  
Petrophysical Parameters ◽  
Resistivity Logs ◽  
Hydrocarbon Saturation ◽  
Niger Delta Basin ◽  
Sand Bodies

Evaluation of the petrophysical parameters in Uzot-field was carried out using Well log data. The target for this study was the D3100 reservoir sand of wells Uz 004, Uz 005, U008 and Uz 011 with depth range of 5540ft to 5800ft across the four wells. Resistivity logs were used to identify hydrocarbon or water-bearing zones and hence indicate permeable zones while the various sand bodies were then identified using the gamma ray logs. The results showed the delineated reservoir units having porosity ranging from 21.40% to 33.80% indicating a suitable reservoir quality; permeability values from 1314md to 18089md attributed to the well sorted nature of the sands and hydrocarbon saturation range from 12.00% to 85.79% implying high hydrocarbon production. These results suggest a reservoir system whose performance is considered satisfactory for hydrocarbon production. Keywords: Petrophysical parameters, porosity, permeability, hydrocarbon saturation, Niger Delta Basin

Fishbone Stimulation Enhances Tight Carbonate Productivity

2021 ◽  
Vol 73 (07) ◽  
pp. 58-59
Author(s):  
Chris Carpenter
Keyword(s):  
Phase 1 ◽  
Carbonate Reservoir ◽  
Growth Strategy ◽  
Abu Dhabi ◽  
Low Permeability ◽  
Successful Implementation ◽  
Well Testing ◽  
Phase 2 ◽  
Carbonate Formation ◽  
Tight Carbonate

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202636, “Fishbone Stimulation: A Game Changer for Tight Carbonate Productivity Enhancement—Case Study of First Successful Implementation at ADNOC Onshore Fields,” by R.V. Rachapudi, SPE, S.S. Al-Jaberi, SPE, and M. Al Hashemi, SPE, ADNOC, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. The operator’s first successful installation of fishbone stimulation technology was aimed at establishing vertical communication between layers in a tight carbonate reservoir and maximizing the reservoir contact. Furthermore, the advanced stimulation technology connects natural fractures within the reservoir, bypasses near-wellbore damage, and allows the thin sublayers to produce. This technology requires running standard lower-completion tubing with fishbone subs preloaded with 40-ft needles and stimulation with the rig on site. Introduction The operator plans to develop tight carbonate reservoirs as part of its production growth strategy. Field Q is a 35×15-km field under development with a phased approach. Phase 1 was planned and production began in 2014. Phase 2 is being developed by drilling wells using the pad concept. Reservoir A, a tight carbonate formation with low permeability ranging from 1 to 3 md and porosity from 15 to 25%, is part of Phase 2 development. The aver-age thickness of Reservoir A is approximately 90 ft across the field, with seven sublayers. The major challenge of Reservoir A development is poor vertical communication and low permeability. Based on appraisal-well data, the average production rate per well is approximately 200 to 400 BOPD with a wellhead pressure of 200 psi. Therefore, appraisal-well testing confirmed the poor productivity of the wells. In addition, the wells are required to produce to the central facilities located in a Phase 1 area 18 km away from Phase 2. In summary, each Phase 2 well is required to be produced against a back-pressure of 500 to 600 psi. Fishbone Stimulation Technology Fishbone stimulation technology is an uncemented-liner rig-deployed completion stimulation system. The liner includes fishbone subs at fixed intervals, and each sub consists of four needles that will connect the sublayers by penetrating into the formation. The typical fishbone completion after installation and jetting the needles in formation is shown in Fig. 1.

scholarly journals Chemostratigraphy of the Upper Jurassic (Oxfordian) Smackover Formation for Little Cedar Creek and Brooklyn Fields, Alabama

Geosciences ◽  
2019 ◽  
Vol 9 (6) ◽  
pp. 269
Author(s):  
Yarbrough ◽  
Engle ◽  
Easson
Keyword(s):  
Upper Jurassic ◽  
Hydrocarbon Production ◽  
Elemental Ratios ◽  
Cedar Creek ◽  
Smackover Formation ◽  
Carbonate Formation ◽  
Chemical Signatures ◽  
Major Producer ◽  
Paleozoic Rocks ◽  
Handheld Scanner

The Upper Jurassic (Oxfordian Age) Smackover Formation is a significant source for hydrocarbon production in southwest Alabama. Brooklyn Field is in southeast Conecuh County, Alabama, and has been a major producer of oil and natural gas for the state. The Smackover is a carbonate formation that has been divided into seven distinct lithofacies in the Brooklyn and Little Cedar Creek fields. In southwest Alabama, the facies distribution in the Smackover Formation was influenced by paleotopography of the underlying Paleozoic rocks of the Appalachian system. The goal of this study is to determine elemental ratios in rock core within the Smackover Formation using an X-ray fluorescence (XRF) handheld scanner and to correlate these elemental characteristics to the lithofacies of the Smackover Formation in the Brooklyn and Little Cedar Creek fields. Eight wells were used for the study within Brooklyn Field and Little Cedar Creek fields. Cores from the eight wells were scanned at six-inch intervals. Chemical logs were produced to show elemental weights in relation to depth and lithofacies. The chemical signatures within producing zones were correlated to reservoir lithofacies and porosity. Aluminum, silicon, calcium, titanium, and iron were the most significant (>95% confidence level) predictors of porosity and may be related to the depositional environment and subsequent diageneses of the producing facies. The XRF data suggests relative enrichments in iron, titanium, and potassium. These elements may be related to deposition in relatively restricted marine waters.

Computed-Tomography Measurements of Water Block in Low-Permeability Rocks: Scaling and Remedying Production Impairment

SPE Journal ◽  
2017 ◽  
Vol 23 (03) ◽  
pp. 762-771 ◽  
Author(s):  
Tianbo Liang ◽  
Xiao Luo ◽  
Quoc Nguyen ◽  
David DiCarlo
Keyword(s):  
Computed Tomography ◽  
Physical Mechanism ◽  
Low Permeability ◽  
Ct Scanner ◽  
Rock Permeability ◽  
Hydrocarbon Production ◽  
The Core ◽  
Water Block ◽  
Low Permeability Reservoirs ◽  
Hydrocarbon Productivity

Summary Fracturing-fluid invasion into the rock matrix can generate water block that potentially reduces hydrocarbon production, especially in low-permeability reservoirs. Here, we experimentally investigate the dynamics of water block under different flow scenarios (i.e., without shut-ins) and rock permeabilities through multiple coreflood experiments. A computed-tomography (CT) scanner is used to obtain the saturation profile within the core throughout the experiment, while the overall hydrocarbon productivity is measured from the overall pressure drop across the core. On the basis of the saturation and pressure measurements, we interpret the potential physical mechanism regarding the productivity reduction from water block and its self-mitigation facilitated by the capillary imbibition. Our interpretation also matches the observed scaling with rock permeability and the optimal shut-in time.

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