The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
- Data Science & Engineering Analytics
The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
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Abstract Static pressure is one of the very important parameters for reservoir engineering, it gives us precious information about our reservoir, such as drive mechanisms, quantities of hydrocarbon in place, patterns, communication between wells, fluid behavior in the reservoir, as consequence, the measurement of this parameter must be conducted on periodical basis, to appropriately know the field and build a good model of reservoir. The advantage of this study can complete other studies that concentrate only on the oil production rate forecasting like Data Driven Production Forecasting Using Machine Learning , Production Forecasting in Conventional Oil Reservoirs Using Deep Learning , Machine Learning Prediction Versus Decline Curve Prediction: A Niger Delta Case Study , Decline Curve Analysis for Production Forecasting Based on Machine Learning  ……, in addition of static pressure evolution of wells. For instance, we can optimize through this study a number of conducted tests to measure static pressure which will minimize operating costs and the probability of accidents occurring the operations, also reduce the shutdown time of wells for completion purpose of such measurement, in addition to the possibility of using this model for other analogue wells that do not have enough pressure measurement, without the need for time and extensive study. Besides, multivariate polynomial regression machine learning algorithm has been developed in this study to predict the evolution of static pressure for existing oil wells.
Al-Sahlanee, Dhuha T. (BP) | Allawi, Raed H. (Thi-Qar Oil Company) | Al-Mudhafar, Watheq J. (Basrah Oil Company) | Yao, Changqing (Texas A&M University)
Abstract Modeling the drill bit Rate of Penetration (ROP) is crucial for optimizing drilling operations as maximum ROP causes fast drilling, reflecting efficient rig performance and productivity. In this paper, four Ensemble machine learning (ML) algorithms were adopted to reconstruct ROP predictive models: Random Forest (RF), Gradient Boosting (GB), Extreme Gradient Boost (XGB), and Adaptive Boosting (AdaBoost). The research was implemented on well data for the entire stratigraphy column in a giant Southern Iraqi oil field. The drilling operations in the oil field pass through 19 formations (including 4 oil-bearing reservoirs) from Dibdibba to Zubair in a total depth of approximately 3200 m. From the stratigraphic column, various lithology types exist, such as carbonate and clastic with distinct thicknesses that range from (40-440) m. The ROP predictive models were built given 14 operating parameters: Total Vertical Depth (TVD), Weight on Bit (WOB), Rotation per Minute (RPM), Torque, Total RPM, flow rate, Standpipe Pressure (SPP), effective density, bit size, D exponent, Gamma Ray (GR), density, neutron, and caliper, and the discrete lithology distribution. For ROP modeling and validation, a dataset that combines information from three development wells was collected, randomly subsampled, and then subdivided into 85% for training and 15% for validation and testing. The root means square prediction error (RMSE) and coefficient of correlation (R-sq) were used as statistical mismatch quantification tools between the measured and predicted ROP given the test subset. Except for Adaboost, all the other three ML approaches have given acceptable accurate ROP predictions with good matching between the ROP to the measured and predicted for the testing subset in addition to the prediction for each well across the entire depth. This integrated modeling workflow with cross-validation of combining three wells together has resulted in more accurate prediction than using one well as a reference for prediction. In the ROP optimization, determining the optimal set of the 14 operational parameters leads to the fastest penetration rate and most economic drilling. The presented workflow is not only predicting the proper penetration rate but also optimizing the drilling parameters and reducing the drilling cost of future wells. Additionally, the resulting ROP ML-predictive models can be implemented for the prediction of the drilling rate of penetration in other areas of this oil field and also other nearby fields of the similar stratigraphic columns.
Habib Ouadi, SPE, is an oilfield operations specialist for the Energy & Environmental Research Center. His focus areas include well drilling, enhanced oil recovery (EOR), carbon capture, utilization, and storage (CCUS), and facilities and well completion. He earned an M.Eng. in petroleum engineering from the University of North Dakota and M.S. and B.S. degrees from the University of Boumerdes, Algeria. He strives to enhance coordination between the energy industry and environmental efforts through research, practice, and advanced technology understanding. Ouadi prepares technical reports, conference papers, journal articles, and outreach materials; develops proposals; and communicates results to clients, stakeholders, the public, and the scientific community.
Liu, Huifeng (CNPC Engineering Technology R&D Company Limited) | Xu, Zhixiong (CNPC R&D, DIFC Company Limited) | Yuan, Zebo (PetroChina Tarim Oilfield Company) | Han, Haochen (PetroChina Tarim Oilfield Company) | Wen, Zhiming (CNPC Engineering Technology R&D Company Limited) | Li, Jianbo (CNPC R&D, DIFC Company Limited) | Song, Lu (PetroChina Tarim Oilfield Company)
Abstract The reservoir pressure coefficient is over 1.80 in the Kelasu foreland area in western China. Heavy mud weighted by ultra-micro barite is used to kill the well for downhole operations. For the wells that have been fractured, the mud easily leaks into the fractures, bringing barite weighting agent into the existing fractures and damaging the well productivity. Re-fracturing is conducted in order to recover the well productivity, but abnormal pumping pressure and proppant screen-out is frequently encountered. Three typical wells that have encountered such problems were analyzed by construction data comparison and using the fracturing simulator StimPlan. The root causes were firstly theoretically analyzed and then laboratory tests were also carried out to verify our theoretical deductions. The comparison results show that the pressure for fracture extension during re-fracturing of the three wells is 20%-40% higher than the initial fracturing; the leakage of the heavy well killing fluid weighted by ultra-micro barite during downhole operations was the main cause of the abnormal pumping pressure and the proppant screen-out during re-fracturing. The laboratory test results showed that the properties of the ultra-micro barite well killing fluid is relatively good after rolling for 15 days under high temperature, but its density and rheological parameters tend to decline due to barite sedimentation; the invasion of the heavy well killing fluid into the matrix reduced the Young's modulus by 3%-5% but increased the Poisson's ratio by 102.42% maximally, which would consequently reduce the dynamic fracture width and lead to abnormally-high pumping pressure and proppant screen-out during re-fracturing. The damage of the heavy well killing fluid to the existing propped fractures was also serious. It reduced the propped fracture permeability by 50%-80% and the retained barite in the fracture was difficult to displace out. Several solutions have also been provided for wells with potential heavy mud damage. In high pressure wells where high-density well killing fluid has to be used during workover, acid-soluble solid is better to be used as the weighting agent. Besides, the re-fracturing pumping schedule should be designed with more and small proppant concentration stages if the well has been damaged by heavy mud so as to avoid screen-out. A barite removing agent was developed to remove the damage caused by barite weighting agent, which can be used for barite removal before hydraulic fracturing so as to avoid abnormal pumping pressure and proppant screen-out. The use of this agent in well BZ-D significantly mitigates the pumping pressure during re-fracturing, and a production increase of 131% was obtained. This paper digs into the impact of heavy mud residue on fracturing extension during re-fracturing through well case study. A method of avoiding abnormal pumping pressure and proppant screen-out, using barite dispersing and chelating agent before re-fracturing, was tried in a well and promising results were obtained. The understandings from this study provide reference for re-fracturing design of wells with potential heavy mud damage.
Boudiba, Younes (SLB) | Pisharat, Maneesh (SLB) | Kelkouli, Mohamed (SLB) | Nettari, Ferhat (Groupement Berkine) | Meddour, Nordin (Groupement Berkine) | Seddar, Bilal (Groupement Berkine) | Babbouchi, Reda Adam (SLB) | Berbra, Abdelhakim (SLB)
Abstract In producing fields, re-mapping reservoir fluid content and new contacts are one of the most important objectives in pursuit of optimized well productivity. Wireline logs and formation testing (FT) data is widely used for this purpose. Continuous fluid data from Advanced Mud Gas (AMG) analysis with downhole logs can be used to generate a comprehensive dataset for reservoir evaluation. Each method has its limitations and advantages. Combining and interpreting the output from the fundamentally different datasets require an experienced petro-technical expert with a specific skill set. To calculate hydrocarbon volume, estimate and forecast reserves, formation fluid evaluation has primarily relied on traditional methods that depends heavily on formation pressure measurements. This was achieved through the analysis of gradients and local fluid contacts. This approach can be misleading for brownfields, where a sizable amount of producible hydrocarbon is left in the reservoir. For characterizing formation fluid, a novel approach utilizing complimentary technologies was adopted. For early hydrocarbon detection and FT program optimization, AMG data was first gathered while drilling. Post drilling open Hole logs, formation pressure and fluid data were acquired not only to verify the AMG findings but also to fill in the gaps regarding water-swept zones, reservoir pressure and depletion, exact fluid contacts, and fluid characteristics to reduce uncertainties. During the job execution, AMG data was effectively used to provide early formation fluid identification and contacts. This information was used to optimize the wireline advanced fluid analysis stations. AMG analysis identified multiple fluids (wet gas, gas condensate, oil, and water) and revealed a much greater complexity of the reservoir than initially expected, which could not have been achieved with standard formation evaluation or other fluid contact identification techniques based on regional gradient analysis. The fluid types and contacts identified by AMG were then confirmed by the wireline downhole fluid analysis. Using this workflow, a high potential recoverable hydrocarbon oil was identified over a reservoir that was classified as a water zone based on initial evaluation and knowledge. In this field, an innovative method was adopted for reservoir fluid characterization. This approach based on digital integration and a unified workflow was used successfully for fluid contact identification, targeted fluid sampling, and identifying and recovering more hydrocarbon from the swept zones.
Guney, Hasan (Dragon Oil) | Ellen, Helby (Dragon Oil) | Ajayi, Ayodeji Temitope (Dragon Oil) | AlAli, Abdulla Ali (Dragon Oil) | Bezziane, Mohamed Lamine (Dragon Oil)
Abstract The Tinrhert Nord Block is located in the Illizi/Berkine-Ghadames Basin where in the central-eastern part of Algeria, near the border with Libya. The sedimentary infill of these basins is composed of thick Palaeozoic sedimentary sequences which constitute a world-class petroleum system, confirmed and producing in Algeria, Tunisia and Libya. Previously drilled wells by Sonatrach in the block had shown a considerable prospectivity for the Block, and further studies were undertaken for well planning and appraisal of the Ordovician, Silurian, and Devonian reservoirs. The target of this study was to better understand the characteristics of the reservoir and quality of the productive series in the block. A comprehensive core study was therefore run for 15 wells with a total of 647 meters of sediments in the Tinrhert Nord block (Figure 3). The study showed that 7 clastic facies for the Palaeozoic sequences can be distinguished. The Ordovician facies subdivided into 3 main facies that were deposited in Glaciomarine, Tidal-Delta and Upper shoreface-shoreline environment and is composed of diamictites, titillates and fine-grained tight reservoir facies. Silurian and Devonian sequences are composed of marine shales that are confirmed as constituting the major source rock in the basin (Silurian hot shale and Frasnian hot shales), and additional fluvial-deltaic coarse-medium-fine grained sandstone facies. SEM (Scanning Electron Microscope), routine core analysis, and fracture studies were performed on selected core intervals in order to perform a more detailed reservoir characterisation. Routine core analysis show that the Ordovician reservoir has a limited porosity up to 4-8% due to the overall texture of the sediments and shows also a low permeability (<1Md). Effective porosity of the Upper Silurian F6 reservoir is up to 15-20% and Devonian F2 reservoir is most likely up to 10%. Core fractures show drilling-induced vertical fractures, and natural hairline type healed fractures, and an additional natural open joint system. The open hole DST well tests that have shown moderate flow rates with can be related to the presence of a high porosity and main permeability system which is composed of interconnected small scale open fractures and larger scale sub-seismic fracture corridors. These features permit to produce also from the reservoir layers that generally show low porosity/permeability facies. These studies confirm that the Silurian F6 reservoirs are the best reservoirs in the basin and Devonian fluvial-deltaic sequences (C and F2)are secondary best reservoir in the basin. The Ordovician reservoirs are tighter with limited porosity and permeability but can be produced by stimulation of the natural fracture system.
Qassabi, Hajir (Petroleum Development of Oman) | Rafliansyah, Andika Putra (Petroleum Development of Oman) | Falla, Johnny (Petroleum Development of Oman) | Al-Yaaribi, Ahmed (Petroleum Development of Oman) | Al-Ruzeiqi, Saleh (Baker Hughes)
Abstract The objective of matrix acidizing in sandstone reservoirs using acid systems that contains Hydrofluoric acid (HF) is to widen the pore throats and spaces in order to increase the permeability around the wellbore and remove formation damage. One major disadvantage of this acid system is the secondary and tertiary reactions, which may lead to precipitations that damage the formation. Because of this, pumping sufficient pre-flush and post-flush volumes of Hydrochloric acid (HCl) is critical to prevent such damaging reactions. However, the placement of such fluids still is a concern in multiple opened layers or long open intervals zones. Stimulating sandstone reservoirs in the Southern fields of the Sultanate of Oman is very challenging, especially in those that exhibit relatively low permeability. These formations, based on petrology work, contains significant amounts of clays and feldspars, which make it difficult in the designing process of the acid formulation. A new version of HF acid system was recently developed. It is specially formulated, so it does not require the addition of Hydrochloric acid (HCl) pre-flush. Because of this, it can be pumped as a Single Stage Retarded Acid System. In addition, its higher reactivity allows deeper penetration, and it has the ability to minimize secondary reactions and damaging precipitates. Lab testing work was conducted to ensure the effectiveness of this Single Stage Retarded Acid System. The results were promising as they show a good improvement in the rock permeability. These results were encouraging to carry field trials in the sandstone reservoirs in Oman Southern fields. Up to now, it has been pumped in sandstones for oil producer wells and for water injector wells. The actual treatment using this system showed increased oil productivity by higher than 60% as well it shows higher than 80% in water injectivity. This paper presents the testing, designing and pumping the SSRAS (Single Stage Retarded Acid System), as well as the comparison with the conventional HF acid system in Southern fields of Oman. It outlines the laboratory work and analysis done as well as the field trials.
Abstract The southern oilfields of Iraq have primarily two rock formations that stand out regarding how to manage fluid losses. The two formations have fluid losses due to their natural vugular porosity in the intermediate section, and additionally, a production zone that presents losses while drilling, thus compromising the hydraulic isolation of the reservoir and validating a dependable barrier above the production zone. The average well profile in this region of the country has a hole size that is usually drilled across these formations of either 17 ½" or 12 ¼" for the first and second loss zones and 12 ¼" or 8 ½" for the third loss zone. This situation renders the conventional solutions to cure losses less likely since the treatment entails a massive quantity of materials to attain success, typically after one or two unsuccessful attempts. For three consecutive years, a thixotropic and acid-soluble cement-based lost circulation treatment shave been ranked as the preferred solution by the operators drilling in these fields. This solution can be pumped through the drilling BHA, it does not exhibit mixing complexities, it is acid soluble, and eventually develops tailored compressive strength which prevents an accidental sidetrack. The stratigraphic column of Southern Iraq has within the first 2,500 meters of depth the Dammam, the Hartha, and the Mishrif formations, which are highly susceptible to lost circulation problems, and ineffective treatment can lead to an increased rig time and accidental sidetracks. This paper describes how this preferred treatment is effective and how to evaluate well conditions to select the treatment volume, explains the regular job execution procedure, and breaks down the key parameters that the treatment fluid needs to demonstrate to maximize the chances of curing losses in the first attempt, enabling rig time and cost savings based on the historical cases from jobs performed in the Zubair and Rumaila fields.
Slimani, Karim (SLB) | Khetib, Tayeb (SLB) | Monfared, Hashem (SLB) | Lamali, Rabah (SLB) | Bendali Amor, Nasrine (SLB) | Skender, Mohamed Semch-Eddine (Sonatrach) | Mezali, Farid (Sonatrach) | Chekou, Hakim (Sonatrach) | Belaifa, Lotfi (Sonatrach)
Abstract Tight oil reservoirs are of paramount importance for an operator holding several fields with important oil potential in Illizi basin, southeastern Algeria. Formation tightness, the presence of nonconnected sand lenses, and the lack of a geological model made it very difficult to maintain the oil production in the studied Devonian reservoir. Consequently, the service company and operator adopted an integrated approach to devise solutions that could restore production in a mature tight oil field that had been closed in 2011. Construction of a geological model for the studied reservoir was challenging because of the high uncertainty in water saturation interpretation caused by the formation water properties (fresh water). A multifunction pulsed neutron service was proposed to provide standalone cased-hole formation evaluation and reservoir saturation monitoring. A unique modeling approaches was applied to characterize the studied tight reservoir and evaluate the reserves based on advanced uncertainty analysis. A hydraulic fracturing design workflow in a reservoir centric stimulation to production software was developed using an integrated approach (geological and geomechanical models) to place the fracture in the optimum reservoir quality and connect the sand lens bodies. Two existing wells were selected to run with the pulsed neutron service, resulting in acquisition of comprehensive reservoir rock and fluid content data. The interpreted logs served to reduce the uncertainty in water saturation modeling and to enable perfect history matching of the producing wells. The constructed geological model was the basis for improving the stimulation designs and maximizing production for future wells. With significant oil initially in place (STOIIP) estimated from the model, the field showed more promise than the previous recorded recovery factor of less than 1%. The field development plan (FDP) identified the location of 20 new infill drilling wells targeting the sweet spots and considering the optimal well spacing. In addition, the plan specified a systematic hydraulic fracturing stimulation job for each newly drilled well to connect and produce the sand body lenses. Recently, a successful campaign of hydraulic fracturing operations was executed on four wells, allowing the operator to resume production from the field. The fracturing performance minimized water cut despite the water-oil-contact (WOC) proximity, and it enhanced the oil recovery. The developed integrated approach has already shown its effectiveness in returning a field to production and improving oil recovery. The approach can be replicated on subsequent wells in the field as well as on similar tight reservoirs all over the world.
The Organization of Petroleum Exporting Countries (OPEC) arose in response to the role of multinational oil companies as the price makers in the international crude market. In an effort to develop a stronger negotiating position, five countries--Iran, Iraq, Kuwait, Saudi Arabia, and Venezuela--founded OPEC in September 1960, with the mission "to coordinate and unify the petroleum policies of its Member Countries and ensure the stabilization of oil markets in order to secure an efficient, economic, and regular supply of petroleum to consumers, a steady income to producers, and a fair return on capital for those investing in the petroleum industry" (OPEC). Since its inception, the founding members have been joined by a rotating cast of other member countries. Currently, Algeria, Angola, Congo, Equatorial Guinea, Gabon, Libya, Nigeria, and the United Arab Emirates comprise the remaining eight of 13 members (Figure 1.) At the time of its inception, OPEC's five founding members controlled 80% of the world's crude exports (Yergin 2008).