Ba Geri, Mohammed (Missouri University of Science and Technology) | Ellafi, Abdulaziz (University of North Dakota) | Flori, Ralph (Missouri University of Science and Technology) | Noles, Jerry (Coil Chem LLC) | Kim, Sangjoon (Coil Chem LLC)
Viscoelastic property of high-viscosity friction reducers (HVFRs) was developed as an alternative fracturing fluid system because of advantages such as the ability to transport particles, higher fracture conductivity, and potential lower cost due to fewer chemicals and equipment on location. However, concerns remain about using HVFRs to transport proppant in DI water and harsh brine solution (e.g. 2wt% KCl and 10 lbs. brine). The primary objective of this study is to investigate the viscoelastic property that can help to understand the true proppant transporting capacity of fracturing fluids in high-TDS environment.
To address the evaluation performance of HVFRs, a comprehensive review of numerous papers associated to viscoelastic property of hydraulic fracturing fluids were investigated and summarized. This paper also provides a full comparison study of viscosity and elastic modulus between HVFRs and among fracturing fluids such as xanthan, polyacrylamide-based emulsion polymer, and guar. Moreover, viscosity profiles and elastic modulus were conducted at different temperatures. Better proppant transportation effect though higher viscosity through Stoke's law and the effect on proppant transportation from elastic modulus comparison were also investigated. Finally, HVFR Conductivity test and successful field test result were explained.
The results of the experimental work show that viscoelastic property HVFRs provides good behavior to transport proppant. Viscosity profile decreased slightly as the temperature increased from 75 to 150 when the DI water was used. While using 10 lbs. Brine the viscosity was reduced by 33%. The longer polymer chains of HVFR indicated better elastic modulus in DI water. The elastic modulus also indicated that the highest values at frequency 4.5 Hz from each amplitude, and lower values as amplitude was increased. Although high molecular weight HVFRs were utilized on the conductivity test, the results observed that the regained permeability was up to 110%. Finally, the promising results from the case study showed that using HVFRs could be performed economically and efficiently for the purpose of proppant transportation and pressure reduction in high TDS fluids.
Al-Maqtari, Ameen N. (SAFER E&D Operations Company) | Saleh, Ahmed A. (SAFER E&D Operations Company) | Al-Haygana, Adel (SAFER E&D Operations Company) | Al-Adashi, Jaber (SAFER E&D Operations Company) | Alogily, Abdulkhalek (SAFER E&D Operations Company) | Warren, Cassandra (Schlumberger) | Mavridou, Evangelia (Schlumberger) | Schoellkopf, Noelle (Schlumberger) | Sheyh Husein, Sami (Schlumberger) | Ahmad, Ammar (Schlumberger) | Baig, Zeeshan (Schlumberger) | Teumahji, Nimuno Achu (Schlumberger) | Thiakalingam, Surenthar (Schlumberger) | Khan, Waqar (Schlumberger) | Masurek, Nicole (Schlumberger) | Andres Sanchez Torres, Carlos (Schlumberger)
A 3D petroleum systems model (PSM) of Block 18 in the Sab'atayn basin, onshore western Yemen, was constructed to evaluate the untapped oil and gas potential of the Upper Jurassic Madbi formation. 3D PSM techniques were used to analyze petroleum generation for conventional reservoirs and the petroleum saturations retained in the source rock for the unconventional system. Block 18 has several proven petroleum systems and producing oil and gas fields. The principal source rocks are within the Madbi Formation, which comprises two units, the Lam and the Meem members. Both contain transgressive organically rich "hot" shales with total organic carbon (TOC) of 8 to 10%; these are located stratigraphically at the base of each member. Additional organic-rich intervals within the Lam and Meem are less-effective source rocks, with lower TOC values.
The PSM consisted of 17 depositional events and 2 hiatuses. To accurately replicate geochemical and stratigraphic variations, the Lam and Meem members were further divided into sublayers. The model was calibrated to present-day porosity, permeability, and pressure data, and it incorporated vertical and lateral lithofacies and organic facies variations. Further calibrations used observed maturities (vitrinite reflectance and pyrolysis Tmax) and present-day temperatures and considered laterally variable heat flow from the Early Jurassic to the Late Miocene. Finally, petrophysical analyses from wells provided calculated hydrocarbon saturations, which were used to calibrate the saturation output from the model. The model satisfactorily reproduces the distribution of the main gas and oil fields and discoveries in the study area and is aligned with well test data.
Maturity results indicate that the upper Lam intervals currently sit within the main to early oil window but are immature at the edges of Block 18 (based on the Sweeney and Burnham Easy R0% kinetics). The lowest Lam unit enters the wet gas window in the center of the block. The underlying Meem member ranges from wet gas to early oil window maturity. Like the Lam, the Meem remains immature along the edges of Block 18. However, in the south of the block, the richest source rocks within the Meem are mainly in the oil window. The degree of transformation of the Meem and Lam varies throughout the members. The model predicts that, at present, the lowest part of the Meem, containing the greatest TOC, has 90% of its kerogen transformed into hydrocarbons.
The model confirms that the Madbi formation is a promising unconventional shale reservoir with a high quantity of hydrocarbons retained within it. Despite the higher quantity of hydrocarbons retained in the upper Meem, in terms of liquid and vapor hydrocarbons predicted in this model, the lower Lam is the most-prospective conventional tight sand reservoir, and the Meem has very small potential as tight sand reservoirs. This study provided a novel application of 3D PSM technology to assess new unconventional as well as conventional plays in this frontier area.
This challenging reservoir characterization case study is defined by the interaction between two reservoirs with different production mechanisms: a fractured basement reservoir and an overlying sandstone reservoir. The existing static geologic concept has been significantly enhanced by integrating pressure data from a unique three-year shut-in period to aid modeling of fractured reservoir connectivity. Previously, the seismic dataset was predominantly used to model the fault and fracture network and guide well planning. In the current approach, the full field data set, including all drilling parameters and new reservoir surveillance data were integrated to address uncertainty in the connected hydrocarbon volume and the relative importance of each production mechanism. The result is a reservoir management tool with which to test re-development concepts and effectively manage pressure decline and increasing gas/oil ratio (GOR) and water production.
To achieve a fully integrated history matched model, the first step was to make a thorough review of the existing detailed seismic interpretation, vintage production logging tool runs (PLT's), wireline logs (including borehole image logs (BHI)) and drilling data to find a causal link between hydraulically conductive fractures and well production behavior. In parallel, a material balance exercise was run to incorporate the new pressure data acquired during the field's shut-in period. The results of the material balance analysis were combined with seismic and well data to define the distribution of connected fractures across the field. Additionally, the material balance analysis was used to determine the connected hydrocarbon volume, the distribution of initial oil in-place and the relative hydrocarbon contribution from each production mechanism.
The field is covered by multi-azimuth 3D seismic and 43 vertical to highly deviated development wells, providing significant static and dynamic data for characterizing the distribution of connected fractures. Despite this high quality, diverse and field-wide dataset, prior modeling iterations struggled to sufficiently describe the production behavior seen at the well level. This has resulted in a major challenge to predicting the production behavior of new development wells and planning for reservoir management challenges. Capturing the complex interaction between production variables (including lithology, matrix versus fracture network, geomechanical stresses, reservoir damage and pressure depletion) at a field level instead of at an individual well level resulted in a unified static and dynamic model that reconciles all scales of observation.
This oilfield represents a unique reservoir characterization opportunity. The result is a key example of how iterative, integrated geological and engineering driven reservoir modeling can be used to inform the development in a complex, mature field. This case study provides an excellent analogue for the reservoir characterization of other fractured Basement fields and/or Basement-cover reservoir couplet fields in the early to late phases of their development.
High-viscosity friction reducers (HVFRs) have been gaining popularity and increase in use as hydraulic fracturing fluids because HVFRs exhibit numerous advantages such as their ability to carry particles, their promotion of higher fracture conductivity, and their potentially lower cost due to fewer chemicals and equipment on location. However, concerns remain about using HVFRs with produced water containing a high level of TDS (Total Dissolved Solids). This study investigates the influence of the use of produced water on the rheological behavior of HVFRs compared to a traditional linear guar gel. This work also aims to correlate proppant settling velocity behavior with rheological properties of HVFRs vs. linear gel on hydraulic fracturing operations. Comprehensive rheological tests of different HVFRs compared with linear gel were performed including, shear-viscosity and dynamic oscillatory-shear measurements using an advanced rheometer.
The results of these rheological measurements reveal that these polyacrylamide-based HVFR systems achieve a high viscosity profile in fresh water with associated high proppant-carrying capacity. On the other hand, increasing water salinity lowers HVFR’s viscosity, increases proppant settling velocity, and lessens the fluid’s proppant-carrying efficiency. Although in fresh water linear gel showed similar viscosity measurements with HVFR-A, the HVFR-A recorded a lower proppant settling rate because HVFR-A has a higher relaxation time (15.3 s) than the relaxation time of linear gel (1.73 s).
As expected, in high-TDS produced water the relaxation time and elastic behavior decreased for all the fracturing fluids tested. HVFR-B recorded the smallest reduction in relaxation time (about 14%) when tested in produced water vs. fresh water, and the resulting settling velocity increased by 29% from 3.4 cm/s to 4.85 cm/s. For linear gel, its reduction in relaxation time exceeded of 70% when changing water salinity from fresh water to high-TDS brine water. This high reduction of relaxation time leads to over 40% increase in proppant settling velocity from 5.3 cm/s to 8.7 cm/s in fresh water and produced water, respectively. This study confirms that HVFR’s elasticity (vs. it viscosity) properties enable successful proppant transport for a wide range of shear rates while viscosity (vs. elasticity) properties controls proppant settling velocity in linear guar-based fluids. This paper will provide greater understanding of the importance of complete viscoelastic characterization of the HVFRs. The findings provide an in-depth understanding of the behavior of HVFRs under high-TDS brine, which could be used as guidance for developing fracturing fluids and for fracture engineers to design and select better friction reducers.
Witte, Jan (Falcon Geoconsulting) | Trümpy, Daniel (DT EP Consulting) | Meßner , Jürgen (Federal Institute for Geosciences and Natural Resources ) | Babies, Hans Georg (Retired from Federal Institute for Geosciences and Natural Resources )
Several wells have encountered good oil shows in the rift basins of northern Somalia, however, without finding commercial hydrocarbons to date. It is widely accepted that these basins have a similar tectonic evolution and a comparable sedimentary fill as the highly productive rift basins in Yemen from which they have been separated by the opening of the Gulf of Aden (fully established in Mid Oligocene). We present new regional tectonic maps, new basement outcrop maps, a new structural transect and new play maps, specifically for the Odewayne, Nogal, Daroor and Socotra Basins.
Digital terrain data, satellite images, surface geology maps (varying scales), oil seep/slick maps, potential data (gravity), well data from ~50 wells and data from scientific publications were compiled into a regional GIS-database, so that different data categories could be spatially analyzed.
To set the tectonic framework, the outlines of the basins under investigation were re-mapped, paying particular attention to crystalline basement outcrops. A set of play maps was established. We recognize at least three source rocks, five reservoirs and at least three regional seals to be present in the area (not all continuously present). Numerous oil seeps are documented, particularly in the Nogal and Odewayne Basins, indicative of ongoing migration or re-migration. Data from exploration wells seem to further support the presence of active petroleum systems, especially in the central Nogal, western Nogal and central Daroor Basins.
Our GIS-based data integration confirms that significant hydrocarbon potential remains in the established rift basins, such as the Nogal and Daroor Basins. Additionally, there are a number of less known satellite basins (on and offshore) which can be mapped out and that remain completely undrilled. All of these basins have to be considered frontier basins, due to their poorly understood geology, remoteness, marketing issues and missing oil infrastructure, making the economic risks significant. However, we believe that through acquisition of new seismic data, geochemical analysis, basin modelling and, ultimately, exploration drilling these risks can be mitigated to a point where the economic risks become acceptable.
We encourage explorers to conduct regional basin analysis, data integration, a GIS-based approach and modern structural geology concepts to tackle key issues, such as trap architecture, structural timing, migration pathways and breaching risks.
Padra Field, located in the eastern margin of south Cambay Basin, India is known for oil and gas production from unconventional fractured basaltic Deccan Trap. Earlier studies of Padra Trap showed moderately weathered basalt as the reservoir rock. However a thorough study integrating core and high resolution image log for characterizing the volcanic reservoir was yet to be ventured. Fracture modeling on PETREL™ platform was attempted using point data from wells and the resultant model was found to be in agreement with production data from wells. Difficulties faced during fracture coding based on FMI™ data owing to highly scattered fracture dip azimuths necessitated the present study to integrate FMI™ with core data.
In the Sab'atayn Basin of Yemen hydrocarbons were generated from pre-salt Upper Jurassic source rocks during the Cenozoic and the salt provides the ultimate seal for the pre-salt and intra-salt traps. Therefore the proper understanding of salt tectonics is critical for ongoing hydrocarbon exploration efforts in the Sab'atayn Basin.
A variety of distinct salt tectonic features are present in the Sab'atayn Basin. Based on the regional interpretation of 2D seismic and locally available 3D seismic reflection data calibrated by exploration wells in the central part of the basin, an Upper Jurassic evaporite formation ("salt" from this point on) produced numerous salt rollers, pillows, reactive, flip-flop, active and falling diapirs.
Due to regional extension, halokinetics began by formation of salt rollers, as soon as the early Cretaceous, within just a few million years after the deposition of the Tithonian Sab'atayn Formation. The salt locally formed salt pillows which evolved to salt diapirs and diapiric salt walls as the result of renewed extension in the basin. As the result of a prominent extensional episode at the end of the Cretaceous most of the diapiric walls in the basin are controlled by large normal faults on their updip flanks. Some of the diapiric walls even evolved into falling diapirs due to ongoing extension
As the Sab'atayn Formation has typically several massive salt intervals in it, it defines post-, intra- and pre-salt play types in the basin. However, other than just providing traps and seals in the basin, salt tectonics is also very important for source rock maturation in the basin. As there are many salt diapirs in the study area, their cooling effect on the the pre-salt hydrocarbon kitchens appears to be quite significant, based on our preliminary basin modelling efforts.
Well bore stability management is key to HSSE and cost effectiveness while drilling. This work focuses on the role of Geosciences to understand, explain and better predict the occurrence of well bore stability issues during onshore drilling operations in Block S2, central Yemen.
To reach the primary reservoir target, the fractured Basement, development wells must penetrate a complex stratigraphic column, characterized by ten key formations and approximately 2000 meters thick. Lithologies vary from sandstones to carbonates, including salt layers with clay intercalations. Severe mud losses are often encountered in poorly consolidated sands of the Lower Tawilah formation where well inclinations are vertical or sub-vertical. At their most severe, they can translate to a complete loss of drilling mud returns on surface. Severe mud losses are not only a threat to borehole stability but they can have a serious impact on the drilling budget and timing.
In order to improve drilling efficiency and speed-up the decision-making process associated with mud losses management and well stability, a detailed Geoscience study has been carried out. This work focuses on identifying three critical factors to explain the occurrence of severe losses:
Despite the challenging working environment and the interaction of geological heterogeneity, pore pressure and stress across the development area, the prediction and prevention of mud losses has been greatly improved while drilling new wells.
The main objective of this paper is to highlight the role these three major elements play during drilling by illustrating with case study examples. Finally, mitigating actions and strategies implemented to prevent and/or deal with severe drilling mud losses are presented.
The area of Interest is located in the northern branch of the Sab’atayn Basin (Marib-Al Jawf-Shabwah Basin), which is a NW-SE trending late Jurassic intra-cratonic rift basin, which lies in southwestern Yemen (Figure 1). The NW-SE trend of the Yemeni Mesozoic rifts reflects an inheritance from deep-seated Precambrian structural trends observed throughout the Arabian Plate, known as the Najd trend. The generalised stratigraphy of the area is shown in Figure 2. This paper particularly focuses on the issues arising while drilling through the Lower Tawilah Fm.
This paper presents a cost versus knowledge-gained appraisal strategy for reducing uncertainty in a tight sandstone reservoir within a short timeframe. More uncertainty should not necessarily demand more data acquisition, rather an approach that focuses on answering the big questions first.
In the Shabwah Basin of central Yemen, sands from the Upper Jurassic Lam Member form fine-grained turbidite lobes. These tight sands, encountered while drilling to the Block S2 Basement reservoir, are currently undergoing appraisal as a potential unconventional oil resource. The presence of oil on surface correlates well with direct and indirect indications of natural fractures during drilling and wireline logging. In contrast, fluid sampling of thin hydrocarbon-bearing sands identified by magnetic resonance tools have so far been unsuccessful. Two possible production mechanisms have been identified in this sandstone reservoir: production from natural fractures and/or production from tight sands by hydraulic fracturing.
The carefully risked appraisal strategy will target the key reservoir uncertainties, productivity and production mechanism, using three kinds of well re-completions: testing production from a well with natural fractures (with or without frac’ing), frac’ing and flowing a well with hydrocarbon-bearing tight sands and, drilling a slanted sidetrack well to increase exposure to natural fractures, with or without frac’ing.
The appraisal approach is objective driven, not a wide-ranging data acquisition programme. There are many unknowns in the reservoir but this project focuses on reducing uncertainty efficiently by prioritising answers to the key objectives which are productivity and the production mechanism.
A decision-tree based appraisal strategy has been developed with clearly defined exit points to control the cost of appraisal versus the value of information gained from the re-completion and drilling activities. This innovative, business-driven approach to reservoir appraisal maximises early uncertainty reduction by the most cost effective methods and can be used as a model for appraisal and early development projects in the industry.
The Lam Member is an appraisal target for a hydraulic fracture campaign in Block S2 Yemen. The exploitation of this poor quality reservoir faces many challenges, which are approached in a carefully risked way to maximise the value of information gained while minimising financial exposure to stakeholders.
The Lam Member of the Madbi Formation was deposited within the Shabwah sector of the Sab’atayn Basin on the southern part of the Arabian Plate during the late Jurassic (Figure 1).
A field-based, portable geochemical laboratory provided Real-Time geochemical rock analysis from 23 stratigraphic wells drilled in the Lusitanian Basin (onshore Portugal), in order to characterize an unconventional resource play. A dedicated workflow involving field personnel, operations teams and remote data users optimized rock measurements and facilitated data interpretation.
This type of workflow, and the approach to make the most of a novel data set, can benefit drilling operations across the border. The technique was developed to support in particular the characterization of shale intervals on a number of adjacent wells, but both the technology applied and the workflow developed are adapt to single-well operations and conventional reservoirs.
The geochemical analysis system analyzed 500 rock samples from 21 shallow stratigraphic wells, outcrops and existing deep legacy wells throughout the Lusitanian basin, from very shallow to depths of more than 2000 m. The targets were three separate organic-rich intervals of Jurassic age. For each sample the complete analysis was carried out on-site and comprised: elemental composition analysis, mineralogy analysis, independent measurement of Total Organic Carbon (TOC) and Pyrolysis. The organic data were the more crucial ones: TOC results combined with Pyrolysis provided accurate information of the amount of hydrocarbons that can be generated by the rock (S2), the rock maturity (Tmax) and the kerogene type (Hydrogen Index), characterizing the organic matter.
The sum of equipment, analytical technique and workflow utilized represented a novel approach to unconventional resource play evaluation. The organic geochemical analyzers utilized in the project have been specifically developed and built for field utilization, permitting to obtain accurate results on a large number of samples in a short time. These results are usually provided by remote laboratories, resulting in delayed responses and the impossibility to react while operating. In other cases, data sets which generate new information are not utilized due to the lack of a proper decision making process which takes them into account. This work model solves all these issues with an integrated approach and allows to adjust and to optimize an ongoing drilling campaign real-time according to the incoming results as well as to interpret the novel geochemical dataset together with the new well data and existing geologic information early on.