Geostatistical-based models provide a considerable improvement for predictive reliability of dynamic models and the following reservoir management decisions. This study focuses on geostatistical modeling the Paleocene Zelten Carbonate reservoir in the Meghil field. The field was discovered in 1959 and production operations began in 1961. Nineteen wells have been drilled to date. The structural framework consists of three slightly asymmetrical anticlinal structures trending NW-SE with steeper dip on the SW flanks. Each of the structures are separated by major normal faults. Seismic interpretation suggests that carbonate build-ups are most likely present on the three separate structures. Edge detection was used to clarify the structural geometries and the presence of additional minor faults. Pillar gridding technique was used to develop the structural framework including four major faults that are partially sealed based on analysis of the available DST and production test data. Stratigraphic analysis indicates a local presentation of dolomitic limestone in the northern portion of the main and the western structures caused considerable litho-facies variation that impacted the distribution of the petrophysical properties. Basic and advanced formation evaluation the net reservoir thickness of about 15 feet with an average porosity of 17% and average water saturation of 35%. Geostatistical-based applications that combine the spatial statistics (e.g. the semivariogram) and the available well and core data were used to populate the reservoir model with porosity, permeability, facies (lithology), net/gross, and water saturation. A conceptual facies model was also used to constrain the reservoir property distributions. Sequential Gaussian Simulation (SGS) was used to populate the model with porosity and water saturation and Sequential Indicator Simulation (SIS) was used to populate the facies model with permeability. The modeling parameters (e.g. semivariogram, correlation coefficients) were significantly constrained by the limited number of wells. Based on the limited number of wells available the semivariogram analysis resulted in a spherical semivariogram model with major axis range of 1435 meters for porosity and 1800 meters for water saturation. Minor axis ranges were about 50% of the major axis ranges. Given the limited well data, a significant effort was made to document the potential impact of the semivariogram parameters on the original hydrocarbon in place (OHIP) estimates and the lateral stratigraphic continuity of reservoir properties. The deterministic approach resulted in place volume estimates of 60 MMBBL and the stochastic approach provided an estimate of 45 MMBBL.
The impact of suspended solids and dynamic conditions on sulphate scale control is well-known. Previous work examined the effect of suspended solids, along with static and turbulent conditions, on one scale inhibitor (Vs-Co). This study has focused on the challenges experienced by an operator of a chalk reservoir field, with a significant amount of carbonate solids in the system, and a high sulphate scale risk due to high barium concentration, injection seawater breakthrough, and cool topside process conditions (20°C). The initial laboratory evaluation showed that the minimum inhibitor concentration (MIC) observed increased from 50ppm to 250ppm after 24 hours (>80% efficiency) under these conditions.
A further study investigated whether a reduction in MIC could be achieved with different chemistry. Various chemicals were screened in conventional static jar tests and in stirred tests to induce turbulence incorporating mixed solids. The results showed that many of the conventional scale inhibitor chemistries, working by nucleation inhibition and crystal growth retardation, could not cope with the severe scaling conditions and were less efficient than the incumbent. However, a "novel" scale inhibitor formulation was shown to work more effectively and resulted in a significantly lower MIC than the incumbent.
Under sulphate scaling conditions (80:20 FW:SW), VS-Co recorded an MIC of 250ppm which was reduced to ≤100ppm with the novel chemical. This resulted in the opportunity for the operator to reduce their chemical dose rate and logistical costs.
This novel chemical works by a combination of nucleation inhibition and crystal growth retardation. As a result of this inhibition mechanism, other operators experiencing similar harsh sulphate scaling conditions could achieve a lower treat rate in high suspended solid loaded systems.
Kashim, Muhammad Zuhaili (PETRONAS) | Giwelli, Ausama (CSIRO) | Clennell, Ben (CSIRO) | Esteban, Lionel (CSIRO) | Noble, Ryan (CSIRO) | Vialle, Stephanie (Curtin University) | Ghasemiziarani, Mohsen (Curtin University) | Saedi, Ali (Curtin University) | Md Shah, Sahriza Salwani (PETRONAS) | M Ibrahim, Jamal Mohamad (PETRONAS)
In line with PETRONAS commitment to monetize high CO2 content gas field in Malaysia, C Field which is a carbonate gas field located in East Malaysia's waters with approximately 70% of CO2 becomes main target for development because of its technical and economic feasibility. Injectivity has been determined as one of the key parameters that determine the success of CO2 storage in field operations. In order to characterize the CO2 injecitivity behavior in C Field, long duration coreflooding experiments has been conducted on two representative core samples under reservoir conditions. The first set of coreflooding test has been conducted on gas zone sample and another one is on aquifer sample. Two important approach has been applied in the experiment in which the first one is where the base rate is established after each incremental stage and the second one is the pre-equilibration of carbonated brine with standard minerals based on the percentage of core mineralogy before saturating the core with aquifer brine to mimic the insitu geochemical conditions of the reservoir. Pre- and post-flooding characterization was conducted using Routine Core Analysis (RCA), X-Ray CT-scan, Nuclear Magnetic Resonance (NMR) and Inductive Coupled Plasma (ICP) to examine the porosity-permeability changes, pore size alterations and the geochemical processes that might take place during CO2 flooding. Based on the differential pressure data, it showed no clear indication of formation damage even after injection of large CO2 pore volume. Pre and post-flooding characterization supported the findings where minor dissolution/precipitation is observed. Overall intrepretation indicates that the critical flowrate is not yet reached for both samples within the maximum rates applied.
Lightweight cements offer significant performance benefits over conventional higher density cement blends, including; improved mechanical properties and stress resilience, lower thermal conductivity, lower ECDs and improved returns to surface and potentially lower risk of casing collapse due to trapped annular pressure. However, a number of challenges exist in developing lightweight blends for thermal applications specifically concerning achieving short wait on cement at low bottom hole static temperature while also ensuring long-term chemical and mechanical stability at high temperatures. Here we report the development of a new lightweight thermal cement by utilizing hollow glass microspheres. Further fine-tuning of the desired slurry properties including controllable thickening times, zero free water, low fluid loss and short WOC was achieved through cost-effective additive adjustment, and the mechanical properties of the cement we validated by long term curing at both ambient and high temperaures (340 °C). To ensure that the high performance achieved in the controlled lab environment was maintained once deployed at full-scale field level an extensive QA/QC program was undertaken. This process involved collecting dry bulk field samples and confirming performance (thickening time, free water, rheology and fluid loss) prior to every job. After initial optimization of the blending process, a 100% success rate was achieved over the course of a more than a twenty jobs. Overall, a high quality lightweight thermal cement with excellent long-term mechanical properties was successfully developed and deployed.
Taher, Ahmed (ADNOC Upstream) | Celentano, Maria (ADNOC Upstream) | Franco, Bernardo (ADNOC Upstream) | Al-Shehhi, Mohammed (ADNOC Upstream) | Al Marzooqi, Hassan (ADNOC Upstream) | Al Hanaee, Ahmed (ADNOC Upstream) | Da Silva Caeiro, Maria (ADNOC Upstream)
In early Aptian times, subtle tectonic movements may have been activated along the NW-SE strike-slip faults and have resulted in a vertical displacement along these faults. The displacement would have allowed the carbonate-producing organisms to colonize along the shallower southern margin and generate well developed reservoir facies. The basinal facies were deposited to the north of the shelf margin, which is known to be the Bab Basin.
Significant oil was discovered in the Shuaiba shelf facies. However, the lagoonal and basinal facies have potential for discovering a significant volume of hydrocarbon, especially in the fields that are located in the Upper Thamama hydrocarbon migration pathways. This potential is supported by the absence of an effective seal separating Thamama Zone-A from Shuaiba basinal facies above, which allowed for the Zone-A hydrocarbon to migrate vertically into the Shuaiba basinal facies. In addition, this potential was supported by the hydrocarbon shows while drilling and by the interpreted well logs, which confirm the presence of movable hydrocarbon in the Shuaiba lagoonal and basinal facies.
The Shuaiba Formation is comprised of two supersequences (
The Shuaiba basinal facies were deposited in an intrashelf basin that was enclosed by the Shuaiba shelfal facies sediments. This resulted in restricted water circulation, anoxic condition and deposition below the wave base. Such depositional environment is favourable for source rock preservation.
Lithologically, Shuaiba basinal facies consist of pelagic lime-mudstone, wackestone and packstone with abundant planktonic microfossils. These facies are characterized by low permeability values, but their porosity can reach up to 20%. The lagoonal sediments consists of a deepening sequence of carbonate sediments, with shallow marine algal deposits at the base and fine hemipelagic to pelagic carbonates in the upper section.
The differences between the Shuaiba Shelf and the Shuaiba Basin are mainly in permeability values. By applying the latest technology in horizontal drilling and hydraulic fracturing, the Shuaiba basinal facies will produce a significant volume of hydrocarbon.
Mohd Hatta, Siti Aishah (PETRONAS Carigali Sdn Bhd) | Zawawi, Irzee (PETRONAS Carigali Sdn Bhd) | Gupta, Anish (PETRONAS Carigali Sdn Bhd) | Ahmad Nadzri, M. Safwan (PETRONAS Carigali Sdn Bhd) | Salleh, Nurfarah Izwana (PETRONAS Carigali Sdn Bhd) | Jeffry, Suzanna Juyanty M. (PETRONAS Carigali Sdn Bhd) | Sharif, Natasha Md (PETRONAS Carigali Sdn Bhd) | Ishak, Izza Hashimah (PETRONAS Carigali Sdn Bhd) | Maoinser, M. Azuwan (Universiti Teknologi PETRONAS)
Field B is a marginal green field located offshore Sarawak, Malaysia with formation depth of less than 1000 meters. The compressional sonic transit time range is from 100 – 115 μs/ft, which immediately triggered the possibility of using active downhole sand control as this range is assumed to be unconsolidated. However, the rock mechanical strength characterization tests from sidewall core indicated contradictory result of a consolidated formation. Since the field is considered as a small field, the cost of the well especially on downhole sand control device need to be extensively optimized. Hence, sand prediction study for a small green field development using field and laboratory measurements was performed.
Several methodologies of sand prediction were utilized to evaluate the optimum sandface completion and sand control management for the field. Empirical and analytical sand prediction based on the well logs, sidewall cores analysis, and sand prediction software are employed to evaluate the likelihood of sand production and the optimum well completion design for the field development. The available data from appraisal wells of Field B is also calibrated to the nearby brown field, Field A that has been producing for more than 30 years.
This paper will discuss on the sand onset prediction results between full perforation versus oriented perforation, and pressure depletion impact on the sand production. The study shows that the formation is not prone to sand production especially in the early part of the production life with high reservoir pressure and low watercut. The expected Critical Drawdown Pressure (CDP) generated from different methods show large variation of sand onset pressure if the sandface is completed using full perforation. Oriented perforation tremendously expands the sand free drawdown limit. Based on the results of the study, expected reservoir pressure depletion and watercut, the completion of the wells adopted Oriented Perforation with no other downhole sand control equipment.
This paper is beneficial for petroleum and well completion engineers especially on sand prediction part of well completion design in development stage. This will assist in ensuring the field meets the EUR and bring forward economic value as well as well integrity assurance.
This paper presents the incorporation of microproppant (MP) in stimulation treatment designs and its effects on well production in the liquids-rich South Central Oklahoma Oil Province (SCOOP) Woodford play. During production, MP can enter and prop open secondary fractures that are too narrow and restricted for even conventional small proppant, such as 100-mesh sand. Descriptions of the MP, area formation, numerical modeling, production results, and offset comparisons are presented.
In unconventional formations, communication between the wellbore and the secondary fracture network, which includes natural fractures and secondary fractures propagated during stimulation, is crucial for improved well production. Perhaps the most difficult objective to accomplish when treating unconventional formations is not just enhancing the number of secondary fractures opened, but increasing the number of those secondary fractures that remain open over a long period of time. During stimulation treatments, MP is pumped during the initial pad stages so it can enter the secondary fractures that are propagated and keep them open when pressure on the formation is relieved during production.
An analysis of treatments and associated numerical modeling conducted within the Woodford play demonstrated the presence of pressure dependent leakoff (PDL), low stress anisotropy, and high net pressures as indications of reservoir complexity. Because of the predicted fracture complexity, a smaller proppant was necessary to prop the narrower secondary fractures. As a result, a series of field trials were conducted to examine the effectiveness of MP for enhancing well production. Comparisons were made between well production where MP was used and offset well production to demonstrate the impact. Production was normalized by pressure and analyzed using square-root time plots. A description of treatment designs used is presented for comparison. The wells in which MP was pumped during the initial pad stages of stimulation treatments demonstrated significant production uplift compared to offset wells.
Additionally, MP demonstrated a secondary benefit, which indirectly manifested in net treating pressure. PDL was believed to be a major contributor to excessively high treating pressures and screenouts in the area. Because the particle size of the MP helped enable better access to the narrower secondary fracture network, it also reduced entry friction associated with PDL. Such a reduction led to lower treating pressures, which subsequently improved placement efficiency of stimulation treatments.
This paper presents the incorporation of microproppant (MP) in stimulation treatment designs in the liquids-rich South Central Oklahoma Oil Province (SCOOP) Woodford and its effects on well production. When MP is used, it can enter secondary fractures that are too narrow and restricted for even conventional small proppant, such as 100-mesh sand, to enter and prop them open during production. Descriptions of the MP, area formation, numerical modeling, production results, and offset comparisons are presented.
In unconventional formations, communication between the secondary fracture network, which includes natural fractures and secondary fractures propagated during stimulation, and the wellbore is crucial for improved well production. Perhaps the most difficult objective to accomplish when treating unconventional formations is not just enhancing the number of secondary fractures opened, but increasing the number of those secondary fractures that remain open over a long period of time. During stimulation treatments, MP is pumped during the initial pad stages so it can enter the secondary fractures that are propagated, and keep them open when pressure on the formation is relieved during production.
An analysis of treatments conducted within the Woodford play, and associated numerical modeling, demonstrated the presence of pressure dependent leakoff (PDL), low stress anisotropy, and high net pressures as indications of reservoir complexity. Because of the predicted fracture complexity, a smaller proppant is necessary to prop the narrower secondary fractures. As a result, a series of field trials were conducted to examine the effectiveness of MP for enhancing well production. Comparisons are made between wells where MP was used and offset well production to demonstrate such impact. A description of treatment designs used is also presented for comparison. The wells where MP was pumped during the initial pad stages of stimulation treatments demonstrated significant production uplift compared to offset wells. Additionally, MP demonstrated a secondary benefit, which indirectly manifests in net treating pressure. PDL is believed to be a major contributor to excessively high treating pressures and screenouts in the area. Because the particle size of the MP enables better access to the narrower secondary fracture network, it also reduces entry friction associated with PDL. Such reduction has led to lower treating pressures, which subsequently has improved placement efficiency of stimulation treatments.
Borhan, N. (Petronas Research Sdn. Bhd.) | Salleh, I. (Petronas Research Sdn. Bhd.) | Ibrahim, J. M. B. M. (Petronas Carigali Sdn Bhd.) | Farrell, A. R. (Scaled Solutions Ltd) | Nichols, D. A. (Scaled Solutions Ltd) | Graham, G. M. (Scaled Solutions Ltd)
The studies involves several unique case for EOR fields in which crude oil samples were collected from from peninsular Malaysia and Borneo. These fields has different reservoir characteristic in pressure, temperature and gas composition. Five Crude Oil from EOR field were undergone Naphthenate acid extraction using acid IER techniques for further instrument analysis to classification of Naphthenate acid type's component. Comparison of soaps-microemulsion generated was then analyse using static bottle test and Naphthenates/ Emulsions Flow Rig Tests. The findings shows the Malaysian crude oil is able to be classified by type of naphthenate acid which are mono-protic acid generating sodium carboxylate soap and tetraprotic acid known as ARN which leads to calcium naphthenate deposit. There are fields that located nearby each other has different characterization of crude and types of acids which leads to different type and severities of soaps-microemulsion and soaps-fines foams formation from apllied EOR chemical. Statics bottle test at higher water cuts shows significant differences with observation from Naphthenates/Emulsions Flow Rig Tests. From this paper classification of Naphthenate acid for Malaysian crude oil has been established with its behavior to induce Soaps-Microemulsion and Soap-Fines Foam in Malaysian EOR Fields using more representive method by Naphthenates/Emulsions Flow Rig Tests.