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.
Well intervention operations in extended-reach wells with sand, proppant, or other fill or in openhole wells are becoming important especially in the Middle East, where many exiting long openhole laterals need to be stimulated to maintain existing production. New laboratory and field results with a lubricant and a 2 ⅛-in. fluid hammer tool are shown to significantly increase the coiled tubing (CT) reach in laterals with sand. These results can be extended to openhole wells, as the coefficients of friction (CoF) between CT and metal casing completely covered with sand or an openhole are similar.
While theoretically increasing the CT diameter could extend the CT reach, in practice, this may not be always possible due to completion size limitations or logistical challenges with onshore road transport or offshore crane lifting/deck loading limitations. Hydraulic technologies such as fluid hammer tools and downhole tractors have extended the CT reach significantly in cased wells, but their successful application in long openhole laterals has not been reported in literature. In addition, metal-on-metal lubricants are used in cased wells with laterals longer than 10,000 ft, but their application in similarly long sand-screen-completed or long openhole laterals is much more limited due to the higher friction.
In this paper, laboratory and field results with a lubricant and a new 2 ⅛-in. fluid hammer tool are presented for sand-screen-completed wells. The lubricant was initially tested in laboratory for compatibility with representative formation rock samples. Given the fact that the lubricant itself contains a clay stabilizer component, it performs better than other commercial lubricants tested in low-, medium-, and high-permeability rock samples. The fluid pumped through the CT and 2 ⅛-in. fluid hammer tool creates pressure pulses with frequency of 8 Hz by opening and closing a valve inside the tool. These pressure pulses generate axial and radial forces that act simultaneously on counteracting the friction force between the CT and the formation: the axial force increases the bottom hole assembly (BHA) tensile load; and the radial force reduces the normal contact force, and thus the friction force. Combining the effects of the lubricant and the new 2 ⅛-in. fluid hammer tool in a pre-job CT modeling software results in CoFs reduced by 50-60%, from a default value of 0.36 without any friction reduction technology to 0.15-0.18 when both the lubricant and the tool are used. Laboratory testing with the lubricant alone showed that CoF between CT and a surface completely covered by sand decreases by 40-50%, from the default value of 0.36 to 0.18-0.22, for temperatures between 20 and 98°C. These CoFs were validated against field data from a sand-screen-completed well in the North Sea. Friction reduction of this magnitude is expected to significantly extend the CT reach in long openhole laterals.
In this paper, the lubricant and the new 2 ⅛-in. fluid hammer tool are briefly described and the data acquired during the laboratory testing and field operation is discussed. These results improve the current industry understanding of the CT friction in sand-filled cased wells and openhole wells and show great benefits in using the extended-reach CT technology consisting of the lubricant, the 2 ⅛-in. fluid hammer tool, and the CT modeling software for extending the CT reach in sand-filled cased and openhole laterals.
At the present time one of the most common methods of well testing is pressure buildup test at the shut-in of production well. When the well is closed for research the process of bottomhole pressure (BHP) increase is accompanied by a change in the dynamic head and increasing the gas pressure at annular space (Shagiev, 1998). Growth of casing pressure above limit pressure can lead to technical problems at wellhead. This paper describes a method for predict the pressure in the annular space and the dynamic head in the end of the pressure transient test and bottomhole pressure buildup to the current reservoir pressure. Express-method of forecasting of casing pressure is tested on experimental examples of research in mechanized wells. In most cases, calculated casing pressure value corresponds with the measured data (successful prediction by this method is 70%). In most cases, forecasting method of casing pressure recovery for vertical mechanized wells allows to determine the possible excess casing pressure above the critical pressure at the wellhead (for example, a possible increase above of test pressure and limit pressure which can connect with some gaps at the wellhead) pressure buildup test. Presented express-method of forecasting can be used in the selection of wells-candidate for well testing, at prevention and reduction of potential problems and for discontinuation well testing due to high casing pressure, improving the success of well testing.
Pityuk, Yu. A. (LLC, RN-UfaNIPIneft) | Davletbayev, A. Ya. (LLC, RN-UfaNIPIneft) | Musin, A. A. (Bashkir State University) | Marin, D. F. (Bashkir State University) | Seltikova, E. V. (Bashkir State University) | Zarafutdinov, I. A. (Bashkir State University) | Kovaleva, L. A. (Bashkir State University) | Fursov, G. A. (LLC, RN-Yuganskneftegaz) | Nazargalin, E. R. (LLC, RN-Yuganskneftegaz) | Mustafin, D. A. (LLC, RN-Yuganskneftegaz)
Interpretation of well testing data allows one to estimate the reservoir state and to choose the corresponding well interventions. However, pressure transient test does not provide detailed information about the state of bottomhole formation zone. One of the methods to increase the number of defined parameters is consideration of temperature dynamics in flowing or shut-in well.
The goal of the present work is development of program code for numerical study of temperature and pressure in production and injection wells. Numerical technique is based on the finite-volume method. Mathematical model describing the distribution of temperature and pressure in the reservoir and the well, taking into account the effects of temperature, such as the Joule-Thomson effect and adiabatic expansion, is considered. Three-dimensional statement allows one to consider complex geometry of the well, hydraulic fractures of different geometry and the anisotropy of the formation.
On the base of numerical simulation the comparative analysis of temperature and pressure distribution in the reservoir and the well with and without fracture is conducted. It is shown that the consideration of the full model "well-formation" is important, because the temperature dynamics in the well and bottomhole formation zone can differ essentially. It is observed that the temperature front in hydraulic fracture propagates faster, than in the reservoir. Effects influencing on the temperature in the injection well differ significantly from the temperature effects appearing in production wells. In production wells the appearance of throttling warm up of liquid on the borders "well-reservoir" and "fracture-reservoir" is observed, the temperature effects are stronger in the presence of the fracture. It is observed the rapid cooling of productive formation due to the convective thermal conductivity and gradual cooling of surrounding rocks due to the conductive thermal conductivity in wells with cold injection.
Developed program code can be useful to design well interventions for cleaning of bottomhole formation zone due to detailed information about state of bottomhole formation zone and hydraulic fracture.