Sand retention testing for screen selection in soft-sand completions has become an integral component to verify the screen performance. This paper describes an improved constant flow-rate test method developed for sand retention testing. The improved constant flow rate test method simulates an erosional-type failure of the formation onto the gravel pack or screen. This test methodology allows the sand to be injected at known concentration into the brine stream, eliminating mixing and settling issues.
The constant flow rate test procedure utilizes a concentrated slurry of the formation sand in brine. This slurry is then injected into the brine flow-stream to accomplish the desired solids concentration for the test (typically 0.5-1.0%). The method allows for flexibility both in the brine flow-rate used and in the solids concentration tested. The slurry injection is accomplished in a slot-flow cell and is designed such that the brine stream erodes the particles from the face of the slurry as it is injected. The distance to the screen after the solids injection is minimized to overcome faster settling of larger particles.
The constant rate sand retention test method provides the amount of solids produced through the screen, the size of the solids produced through the screen, the retained permeability of the screen, and the pressure increase over time as the formation is deposited on the screen. Detailed in the paper is a reproducibility study that was included in order to verify the test method. Additionally, a comparison between the constant flow rate and constant drawdown test has been conducted using the new constant flow rate test method. The new constant flow rate test method has been found to have greater reproducibility than the previous method. Additionally, the constant flow rate and constant drawdown test have been found to produce similar test results with known exceptions that are detailed in the finding.
The improved constant flow rate test method provides more consistent, reproducible results to assist in determining the optimal sand control screen for a target completion.
Hernandez, J. (Total SA) | Lai, B. H. (Total E&P Angola) | Bahabanian, O. (Total SA) | Goyallon, D. (Total E&P) | Nordin, A. A. Ahmad (Schlumberger) | Nwafor, C. E. (Schlumberger) | Taleballah, E. Y. (Schlumberger) | Semin, L. (Schlumberger)
Field A is a significant contributor within the Kaombo development project, offshore Angola. The field comprises five stacked sedimentary units (A1 through A5, from top to bottom) requiring openhole gravel packs (OHGP) as the sand control technique, and a commingle strategy was key to reducing well count. Production from reservoir A4 could not be commingled with that from other sedimentary layers due to the risk of asphaltene precipitation, and A3, water bearing in one panel, also required isolation. The openhole mechanical packer (OHMP) with OHGP completion was used in field A to reduce the well count from the originally planned eight oil producers (OP) to six OP; this brought savings in excess of USD 100 million. Well 1 in field A penetrates all five reservoirs; it was successfully completed in December 2016 with two OHMPs isolating reservoir A4. A well in field B was successfully completed in May 2017 with one OHMP to allow future water shutoff (WSO) with potential production acceleration as well as estimated ultimate recovery (EUR) increase of more than one million barrel of oil equivalent (MMboe). Downhole gauge data analysis combined with mass balance indicated that 100% pack efficiency was achieved in both wells with the expected packing sequence in the presence of packers bypassed with shunt tubes.
The OHMP enhances the versatility of OHGP completions with eccentric shunt-tube screen assemblies, which enable applications such as selectivity, zonal isolation, and water shutoff. The robustness of OHGP completions together with the features mentioned earlier will improve the economics for future projects by reducing capital expenditure (capex) and increasing reserves recovery per well. This application was an important contributor to reduce drilling expenditure (drillex) for the Kaombo development project.
With increasing focus on identifying cost effective solutions to well design with minimal impact on productivity, this paper will focus on an alternative to cesium formate as perforation fluid in the HPHT Gudrun field operated by Statoil. Cesium formate has been used with success for drilling and perforating many HPHT wells. However, given the significant cost of this fluid coupled with low oil prices, Statoil wanted to perform testing to assess the performance of an alternative low ECD oil based mud as a perforation fluid. The paper will describe the extensive qualification testing that has been performed. This includes coreflooding using representative plugs from Gudrun under downwhole temperature and pressure conditions. In addition, eight Section IV perforation tests have been performed to compare the performance of Cs formate and the low ECD oil based mud. These tests were undertaken using gas and oil saturated cores to reflect different production scenarios. The main aspects of the perforation operation that were reflected in the test design were as follows. Perforating at reservoir pressure and laboratory testing temperature of approximately 100°C Simulating an extended shut in period after perforation Undertaking a clean up sequence using scaled down flowrates
Perforating at reservoir pressure and laboratory testing temperature of approximately 100°C
Simulating an extended shut in period after perforation
Undertaking a clean up sequence using scaled down flowrates
Based on the results of the coreflooding combined with the section IV 19B testing, the low ECD OBM was selected as the perforating fluid for use on Gudrun. The perceived benefits of using the low ECD OBM were as follows. Simplification: use of the same fluid for drilling and perforating the reservoir section. Tangible cost savings in fluid cost and time savings of approximately 40M NOK ($5M). Potentially increased productivity compared to cesium formate. Improved standardization of the operational sequence.
Simplification: use of the same fluid for drilling and perforating the reservoir section.
Tangible cost savings in fluid cost and time savings of approximately 40M NOK ($5M).
Potentially increased productivity compared to cesium formate.
Improved standardization of the operational sequence.
Perforation modelling is described and comparison is made between this and the Section IV tests. Finally, the well start-up experiences and production data are presented demonstrating the effectiveness of the low ECD oil based mud as a perforation fluid.
Many shale and limestone formations exhibit natural fractures in the form of calcite veins. Although these natural fractures might be sealed, they are prone to activation in hydraulic fracturing operation due to their low mechanical properties. Once these fracture are activated, the flow in such fractures without proppants play a role not only in production performance but also in analyzing the mechanisms responsible for the low recovery of water flowback. To address this issue, we created induced fractures within calcite veins of Niobrara formation using indirect tensile experiment and fracture permeability experiments were conducted by injecting both water and gas. The results of fracture permeability tests in Niobrara formation were compared with the results of fracture permeability tests in granite sample. The effective fracture permeability to water is significantly lower than the fracture permeability to gas in calcite veins while the fracture permeability of granite sample to both water and gas is almost similar. Comparing the fracture permeability of the Niobrara sample with the granite sample provides some insights into the possibility of water trapping microfractures as a possible reason for low water-flowback recovery. Besides the interaction of water with rock, fracture roughness can be another mechanism affecting fracture permeability. To this end, the topographic surface of samples were measured by laser profilometer and the fluid flow in rough fractures were simulated numerically to analyze the effect of roughness on fracture permeability.
Soft sand wells are typically more expensive completions due to the need for sand control. The cost of the wells makes the completions more high-risk and increases the need for laboratory testing to validate the screen or gravel pack sizing as well as drill-in fluid selection and filtercake cleanup. Dynamic drill-in fluid clean-up testing provides a state of the art methodology for determining the least damaging drill-in fluid and / or the most effective clean-up treatment for the filtercake. However, the test method to date, referenced in SPE 112497 and SPE 179024 has used a 100% uniform clean-up treatment approach. This approach has assumed that all of the clean-up treatment uniformly contacts and treats the filtercake. In the actual well, it is unlikely that 100% uniform clean-up exists. It is possible in the wellbore to encounter selective clean-up treatment leakoff due to permeability differences or variable filtercake thickness. This paper investigates the results when a less uniform clean-up environment is encountered.
The dynamic drill-in fluid testing utilizes designed-for-purpose slot flow cells which allow soft sand formations to be confined and tested while still exposing the face of the formation directly to the drill-in fluid or clean-up treatment during the test. The well conditions are received from the client and the shear rate at the formation face is calculated and matched in the laboratory. The test simulates wellbore conditions as closely as possible including annular shear rate during filtercake deposition, overbalance pressure, temperature and multiple clean-up flushes. In this study, the amount of filtercake clean-up treatment fluid loss was modified to simulate multiple effective clean-up scenarios. Additionally, testing was completed on aloxite discs in a standard HPHT fluid loss cell in order to provide a comparison between the dynamic and static tests.
The dynamic fluid loss testing has been designed to match treatment volumes and conditions in the actual wellbore as closely as possible. The assumption that 100% uniform application of the clean-up treatment contacting the filtercake has always been the basis for the testing. However, changing the previous assumptions to allow for non-uniform application of the clean-up treatment during the testing provides another opportunity to challenge our perceptions and simulate the actual well more completely.
The modification of the standard test procedure to allow the simulation of non-uniform clean-up of the filtercake in the wellbore adds further to our understanding of the actual wellbore clean-up. The relationship of the results between the static and dynamic fluid loss provides an opportunity for pre-screening work to be conducted and related to the final results achieved in the dynamic fluid loss test.
Ma, Xin (China University of Petroleum East China) | Lei, Guanglun (China University of Petroleum East China) | Wang, Zhihui (China University of Petroleum East China) | Da, Qi'an (China University of Petroleum East China) | Song, Ping (China University of Petroleum East China) | Zhang, Xin (China University of Petroleum East China) | Yao, Chuanjin (China University of Petroleum East China)
As the development of unconventional oil and gas reservoirs, hydraulic fracturing has become a critical component. However, formation damage is always impeding the application of hydraulic fracturing. A remediation method is presented that microbes can be used to remove the guar-based fracturing fluid damage. Laboratory experiment results show the feasibility and effectiveness of this method in different reservoir temperature.
This approach is based on the bio-degradation of guar gum. Guar gum degrading bacteria was isolated from the well water and identified through 16S rDNA. Apparent viscosity and average molecular weight were employed to measure the bio-degradation. The mechanism of microbial remediation of guar-based fracturing fluid damage was proved by the biodegradation of filter cake through measuring the thickness of filter cake on the filter paper. In addition, the core-flood simulation experiment was also conducted to verify the feasibility of this method. The experimental method is described in detail to permit readers to replicate all results.
Three guar gum degrading bacterial strains,
The novelty of the new method is in the ability to remove the polymeric damage using the bacteria when the formation was damaged after hydraulic fracturing.
Innovation continues to be a driving force within the petroleum industry, particularly in the service sector. Technological breakthroughs often differentiate winners and losers in this highly competitive environment and frequently lead to improved production and real value. Advances this century in hydraulic fracturing technologies have combined to reshape the global oil market by making tight gas and mudstone unconventional plays more viable. Conversely, technologies developed decades ago have also consistently shown new life and new applications when combined with these recent technological innovations.
The successful application of a revitalized non-aqueous hydraulic fracturing fluid system, first developed in the early 90's for diesel and crude oil to tackle some of the most sensitive and technically challenging formations, is documented in this case history. A brief summary of the historical application of this fracturing fluid system and the reasons for lack of applications is included. The current application of this technology, in tandem with a new refined mineral oil based fluid system energized with CO
Offset wells completed with alternate technologies during the same time period were weighed against wells treated with the updated 1990's era technology. The revitalized system surpassed these comparative technologies in terms of both cumulative hydrocarbon production and decreased decline rates.
This case history demonstrates not only the efficacy of the documented fracturing treatment design, but also the value in combining old and new technologies as an effective method to provide innovative solutions in challenging reservoirs.
Injectivity decline by fines migration with two-phase flow is important in low-salinity and smart waterflooding in oilfields. The complexity of detachment of the natural reservoir fines, their mobilization, migration and straining in two-phase environment preclude simple formulae for injectivity decline prediction. The objective of the present study is to derive of the semi-analytical model for two-phase axi-symmetric flow with variation of injected salinity, fines migration, and consequent permeability damage. A simple and robust model allows investigating the effects of injection rate, injected salinity, oil viscosity, relative permeability, and kaolinite content in the rock on skin-factor growth.
Borazjani, Sara (The University of Adelaide) | Behr, Aron (Wintershall Holding GmbH) | Genolet, Luis Carlos (Wintershall Holding GmbH) | Kowollik, Patrick (Wintershall Holding GmbH) | Zeinijahromi, Abbas (The University of Adelaide) | Bedrikovetsky, Pavel (The University of Adelaide)
We derive a general system of equations accounting for two-phase fines migration with fines mobilization by injected water with different salinity, rock plugging by the migrating fines and consequent permeability damage in the swept reservoir zones. The analytical model derived contains explicit formulae for water-saturation and ion-concentration fronts along with pressure drop and water-cut in production wells. The model developed is applied to the cases of heavy oils, in low consolidated rocks with different clay composition and different injected and formation water compositions.
We show that non-equilibrium effects of the delayed fines release highly affect incremental oil during injection of different-salinity water. The oil-recovery is maximum for fast fines release. For slow fines release, the recovery tends to that of "normal" waterflooding.
The fines-migration-assisted smart waterflood is successful in reservoirs with a high content of fines-generating clays in the rocks (kaolinite, illite, and chlorite).
A novel analytical model presented in the paper allows predicting reservoir behavior and incremental oil for different compositions of injected water and clay contents in the rock. It permits recommending ionic-composition for the injected water.
Roostaei, M. (University of Alberta) | Nouri, A. (University of Alberta) | Fattahpour, V. (University of Alberta) | Mahmoudi, M. (University of Alberta) | Izadi, M. (Louisiana State University) | Ghalambor, A. (Oil Center Research International) | Fermaniuk, B. (RGL Reservoir Management)
Standalone screen (SAS) design conventionally relies on particle size distribution (PSD) of the reservoir sands. The sand control systems generally use D-values, which are certain points on the PSD curve. The D-values are usually determined by a linear interpretation between adjacent measured points on the PSD curve. However, the linear interpretation could result in a significant error in the D-value estimation, particularly when measured PSD points are limited and the uniformity coefficient is high. Using the mathematical representation of the PSD is an efficient method to mitigate these errors. The aim of this paper is to assess the performance of different mathematical models to find the most suitable equation that can describe a given PSD.
The study collected a large databank of PSDs from published SPE papers and historical drilling reports. These data indicate significant variations in the PSD for different reservoirs and geographical areas. The literature review identified more than 30 mathematical equations that have been developed and used to represent the PSD curves. Different statistical comparators, namely, adjusted R-squared, Akaike's Information Criterion (AIC), Geometric Mean Error Ratio, and Adjusted Root Mean Square Error were used to evaluate the match between the measured PSD data with the calculated PSD from the formulae. The curve fit performance of the equations for the overall data set as well as PSD measurement techniques were studied. A particular attention was paid towards investigating the effect of fines content on the match quality for the calculated versus measured curves.
It was found that certain equations are better suited for the PSD database used in this investigation. In particular, Modified Logestic Growth, Fredlund, Sigmoid and Weibull models show the best performance for a larger number of cases (highest adjusted R-squared, lowest Sum of Squared of Errors predictions (SSE), and very low AIC). Some of the models show superior performance for limited number of PSDs. Additionally, the performance of PSD parameterized models is affected by soil texture: For higher fines content, the performance of equations tends to deteriorate. Moreover, it appears the PSD measurement techenique can influence the performance of the equations. Since the majority of the PSD resources used here did not mention their method of measurement, the effect of measurement technique could only be tested for a limited data, which indicates the measurement technique may impact the match quality.
Fitting of parameterized models to measured PSD curves, although well known in sedimentology and soil sciences, is a relatively unexplored area in petroleum applications. Mathematical representation of the PSD curve improves the accuracy of D-values determination, hence, the sand control design. This mathematical representation could result in a more scientific classification of the PSDs for sand control design and sand control testing purposes.