Telang, Milan (Kuwait Oil Company) | Al-Matrook, Mohammad F. (Kuwait Institute for Scientific Research) | Oskui, Gh. Reza (Kuwait Institute for Scientific Research) | Mali, Prasanna (Kuwait Oil Company) | Al-Jasmi, Ahmad (Kuwait Oil Company) | Rashed, Abeer M. (Kuwait Institute for Scientific Research) | Ghloum, Ebtisam Folad (Kuwait Institute for Scientific Research)
Asphaltene deposition problems in Kuwait have become a serious issue in a number of reservoirs during primary production in different fields, resulting in a severe detrimental effect on the economics of oil recovery. Hence, one of the mitigation approaches in the field is using remedial solvent treatments, such as Xylene or Toluene, which is very costly and harmful to the environment.
Kuwait Oil Company (KOC) is planning to produce from asphaltinic Marrat wells that have been shut down due to low bottom-hole pressure (BHP), by artificial lifting technique using an Electric Submersible Pump (ESP) supported with continuous chemical injection, as a pilot. The main objective of this study was to investigate in the lab the effectiveness of various concentrations of toluene/diesel (T/D) mixtures on Marrat reservoir fluid in order to mitigate asphaltene deposition problem during the actual pilot implementation.
Preliminary screening tests were conducted on the surface oil sample using Solid Detection System (SDS) "laser technique?? to determine the optimum dose of the T/D mixture ratio. The results showed that pure diesel accelerated the asphaltene precipitation; however, mixing T/D inhibited the precipitation process. Series of pressure depletion tests was then conducted on live oil , single phase samples, to determine the Asphaltene Onset Pressure (AOP) with and without adding various ration of T/D solvents at different temperatures from reservoir to surface conditions.
The results revealed that using 15% (by volume of oil) from the (50T:50D) mixture reduced the AOP close to the bubble point pressure. Furthermore, the amount of the precipitated asphaltene was physically quantified using a bulk filtration technique. It was observed that, based on blank sample, the wt% of the precipitated asphaltene was minimized at the AOP and maximized at the bubble point. However, using the recommended mixture of 50T/50D, the amount of asphaltene that precipitated was almost negligible. Therefore, from a health, safety, and economic point of view, this study recommends using a low dose of 7.5% (by volume of oil) from toluene mixture with diesel (50%:50%) rather than using pure toluene to prevent the precipitation.
Blunt, Martin Julian (Imperial College) | Al-Jadi, Manayer (Kuwait Oil Company) | Al-Qattan, Abrar (KOC) | Al-Kanderi, Jasem M. (Kuwait Oil Company) | Gharbi, Oussama (Imperial College) | Badamchizadeh, Amin (CMG) | Dashti, Hameeda Hussain (Kuwait Oil Company) | Chimmalgi, Vishvanath Shivappa (Kuwait Oil Company) | Bond, Deryck John (Kuwait Oil Company) | Skoreyko, Fraser A. (CMG)
The Magwa Marrat reservoir was discovered in the mid-1980s and has been produced to date under primary depletion. Reservoir pressure has declined and is approaching the asphaltene onset pressure (AOP). A water flood is being planned and a decision needs to be taken as to the appropriate reservoir operating pressure. In particular the merits of operating the reservoir at pressures above and below the AOP need to be assessed.
Some of the issues related to this decision relate to the effects of asphaltene deposition in the reservoir. Two effects have been evaluated. Firstly the effect of in-situ deposition of asphaltene on wettability and the influence that this may have on water-flood recovery has been investigated using pore scale network modes. Models were constructed and calibrated to available high pressure mercury capillary pressure data and to relative permeability data from reservoir condition core floods. The changes to relative permeability characteristics that would result from the reservoir becoming substantially more oil-wet have been evaluated. Based on this there seems to be a very limited scope for poorer water flood performance at pressures below AOP.
Secondly the scope for impaired well performance has been evaluated. This has been done using a field trial where a well was produced at pressures above and substantially below AOP and pressure transient data were used to estimate near wellbore damage "skin??. Also compositional simulation has been used to estimate near wellbore deposition effects. This has involved developing an equation of state model and identifying, using computer assisted history matching, a range of parameters that could be consistent with core flood experiments of asphaltene deposition. Results of simulation using these parameters are compared with field observation and used to predict the range of possible future well productivity decline.
Overall this work allows an evaluation of the preferred operating pressure, which can drop below the AOP, resulting in lower operating costs and higher final recovery without substantial impairment to either water-flood efficiency or well productivity.
A live oil sample was subjected to a solid detection system (SDS) to measure asphaltene onset point (AOP) at 3850 psi, and asphaltene content of 1.3%. A high-resolution digital camera was used to measure asphaltene particle size distribution. The result showed that asphaltene particles were not uniform in size, but has a normal distribution of 100-120 µm. Asphaltene reversibility to dissolved back into the oil with increasing pressure was only 35% of the original deposition. Two core samples were examined for formation damage due to asphaltene deposition. A Low permeability core showed significant permeability reduction exceeding 50% of its baseline permeability, and the higher permeability core showed less permeability decline, even with the same asphaltene precipitation.
Stanitzek, Theo (AkzoNobel) | De Wolf, Corine (AkzoNobel) | Gerdes, Steffan (Fangmann Energy Services) | Lummer, Nils R. (Fangmann Energy Services) | Nasr-El-Din, Hisham A. (Texas A&M University) | Alex, Alan K. (AkzoNobel)
Matrix acidizing of high temperature gas wells is a difficult task, especially if these wells are sour or if they are completed with high chrome content tubulars. These harsh conditions require high loadings of corrosion inhibitors and intensifiers in addition to hydrogen sulfide scavengers and iron control agents. Selection of these chemicals to meet the strict environmental regulations adds to the difficulty in dealing with such wells. Recently, a new environmentally friendly chelating agent, glutamic acid -diacetic acid (GLDA), has been developed and extensively tested for carbonate and sandstone formations. Significant permeability improvements have been shown in previous papers over a wide range of conditions. In this paper we evaluate the results of the first field application of this chelating agent to acidize a sour, high temperature, tight gas well completed with high chrome content tubulars.
Extensive laboratory studies were conducted before the treatment, including: corrosion tests, core flood experiments, compatibility tests with reservoir fluids, and reaction rate measurements using a rotating disk apparatus. The treatment started by pumping a preflush of mutual solvent and water wetting surfactant, followed by the main stage consisting of 20 wt% GLDA with a low concentration of a proper corrosion inhibitor. Following the treatment, the well was put on production, and samples of flow back fluids were collected. The concentrations of various ions were determined using ICP. Various analytical techniques were used to determine the concentration of GLDA and other organic compounds in the flow back samples.
The treatment was applied in the field without encountering any operational problems. A significant increase in gas production that exceeded operator expectations was achieved. Unlike previous treatments where HCl or other chelates were used, the concentrations of iron, chrome, nickel, and molybdenum in the flow back samples were negligible, confirming low corrosion of well tubulars. Improved productivity and longer term performance results confirm the effectiveness of the new chelate as a versatile stimulation fluid.
Adhi gas-condensate field is located near Islamabad, Pakistan. Pakistan Petroleum Limited started fluid processing and recovery of Liquefied Petroleum Gas and Condensate around in 1990. The liquid stream was processed with no solids deposition in the past. Recently, the liquid processing circuit of the plant has experienced an increasing amount of black solid deposition, which is trapped into the liquid filters located in the plant.
To identify the root causes of the problem of these solids depositional systematic approach was applied including taking various solid, liquid and gas samples from the plant inlet and various locations inside the processing plant and analyzing them for diagnostics.
Based on the outcome of the root-cause analysis, a chemical mitigation strategy has been developed, tested and implemented, resulting in significant reduction in problems related with solid depositions in processing plant.
Adhi gas condensate field is located near Islamabad, Pakistan. The fluid in Adhi is processed in two liquefied Petroleum Gas (LPG)/Natural Gas Liquid (NGL) plants (plants I and II) and Oil Stabilization Facility (OSF). The condensate was processed without solid deposition in these plants from 1990 to 2007.
The black solid deposits started to accumulate on the process equipment and plants' filters (Figure-1)leading to a high filter change frequency and consequent production loss.
Due to the continuous increase of the severity of the problem, a full Flow Assurance (FA) review of the field was carried out in order to mitigate the solid precipitation and problem of its depositions in plant. The first phase of the FA review was to conduct a Root Cause Analysis (RCA) where the main causes were identified including fluid compositional changes, temperature and pressure changes across the system, and incompatibility of mixing well streams with different compositions were identified to be the main causes for the asphaltenes dropout.
The RCA was based on the historical plant production data, fluid sampling, analysis results and asphaltene thermodynamic modeling.
The outcomes were:
This article details the methodology followed in solving the solid deposition problem at Adhi.
The prediction of the risk of asphaltene precipitation is an important topic in the petroleum industry. It usually requires representative samples and measurements using specialized, high-pressure equipment, and may have to be performed on many different fluids from various reservoirs. Of the many fast screening methods have been proposed, most of them only take into account the hydrocarbon phase without any investigation on the actual asphaltenes in the crude, and may lead to erroneous predictions.
This paper presents a universal approach of the risk of precipitation of asphaltenes.
A new experimental way to perform fast screening of asphaltene instability is proposed based on relevant solubility properties of the asphaltene fractions. It is based on two major parameters: the live oil solvent properties (based on PVT analyses) and the actual solubility of asphaltene fraction, through an easy characterization procedure that examines the solubility of asphaltenes in heptane/toluene mixtures. In field development projects, this method, which can be performed on dead oil samples, helps limit the investigation to fluids that present a real risk of asphaltene precipitation.
If a precipitation risk is stated, two paths are followed in order to estimate the risk level, and to prepare a mitigation strategy. Additional tests, performed on pressurized representative samples or taking into account reorganization of asphaltenes from different fluids, will help to define the severity of the risk. For mitigation, an advanced test set-up has been developed, which facilitates evaluation of the efficiency of chemical additives to prevent plugging under flow conditions of fluids above the asphaltene precipitation threshold. Depending on the crude oil, the severity of the precipitation conditions, and the nature of the additive, the blocking of a capillary tube can be delayed or prevented.
Hydrocarbon gas injection has proven to be one of the most efficient Enhanced Oil Recovery (EOR) methods, especially for tight and heterogeneous reservoirs with light to medium API oil, where water flooding is expected to be inefficient. Asphaltene precipitation and deposition, however, might occur due to pressure and fluids compositional changes with the gas injection. This complex phenomenon requires experimental and numerical investigation to understand the conditions at which flow impairment due to asphaltene formation damage may occur, resulting in lowering well flow capacity and in turn lower ultimate oil recovery.In this experimental study, low permeability carbonate rock core samples were flooded with hydrocarbon gas under reservoir conditions. The floods were conducted on core samples of two different lengths representing two different rock types based on average rock permeability and Pore Throat Size Distribution (PTSD). Additionally, these core samples were flooded at two different operating conditions to mimic the average reservoir and the wellbore flowing pressure conditions. As a prelude to these experiments, Asphaltene Onset Pressure (AOP) and Asphaltene Onset Concentration (AOC) of the oil under study with the injection gas were established through NIR, SARA and Titration analysis.Flow impairment due to formation damage by asphaltene precipitation and deposition was analyzed through permeability measurements before and after gas flooding. In all cases permeability reduction was observed. Permeability reduction was found to be function of rock types, reservoir pressure, and length of composite core samples. We assume that pore throat bridging by the larger size asphaltene particles caused higher permeability reduction in the samples of poorer rock types. Experiments conducted at lower pressures showed more damage. This is consistent with the lower AOC at lower pressure. Longer core samples give more time for asphaltene flocculation resulting in more asphaltene formation damage and more permeability reduction. Scanning Electron Microscopic (SEM) images of core plugs before and after the gas flooding process were found to be not conclusive with respect to direct detection of asphaltene deposition in the core samples and further work is planned to positively identify asphaltene deposition in the rock samples.
Asphaltene are the polar, polyaromatic and heaviest hydrocarbon fraction of crude oil that are soluble in light aromatic hydrocarbons and solvents such as benzene and toluene but insoluble in low molecular weight
parafins1-4. As a result of reservoir fluid depressurization, asphaltene particles may deposit on the formation rock surface and/ or to plug the rock pore throats. Another practical reason reported in the literature is the injection of different solvents for oil displacement during Enhanced Oil Recovery (EOR) processes, which often leads towards the reservoir fluid composition alteration and hence results in the Asphaltene flocculation and deposition.
This paper describes some of the operational aspects, planning practices and improvements in both coil tubing and bullhead acid stimulation campaigns carried out to increase the performance of gas-producing wells in a mature sour-gas asset. The objective of the campaign was to reduce operational costs by flowing the wells back directly into the production facilities after the treatment, without the use of temporary production test equipment. This strategy would be considered successful, if it could be proven to be technically well-executed, and compliant with HSSE directives. By engaging in a multi-disciplinary approach, critical aspects of this campaign were identified at an early stage, including selection of fit-for-purpose stimulation formulation. Furthermore a novel corrosion inhibitor capable of withstanding unspent acid in a sour system was deployed in the facilities for integrity and protection.
Key performance indicators for the campaign were set, including target pH values for flowback samples. Monitoring of H2S concentration of the produced gas was carried out, and control with the use of a H2S scavenger injected in well flowlines allowed for export gas specifications to be maintained. Overall the campaign generated significant productivity improvements. This cost-effective acid stimulation is therefore a valuable tool for well reservoir and facilities management in the asset.
As the severity of sour drilling applications has increased, the requirement for drill stem materials resistant to sulfide stress cracking (SSC) has accelerated. Sour service drillpipe, traditionally manufactured with SSC resistant upset tubulars and tool joints, has been available for some time. Sour Service drillpipe metallurgy is not specifically controlled by NACE MR 0175/ISO 15156,1 however these tubulars and tool joints are often evaluated in accordance with the standard. The friction welds joining the upset tubulars and tool joints were not resistant to SSC and were not evaluated. This has been acceptable for many sour drilling applications since the weld is not the mostly highly stressed region of the drillpipe joint and because the operator has a certain degree of control over the environment through the drilling fluid properties and additives. As more severe environments with higher Hydrogen Sulfide (H2S) concentrations were identified for exploration and development, it became apparent that a fully SSC resistant drillpipe system including the friction welds was necessary.
This paper presents the successful development and qualification of SSC resistant friction welds for critical sour applications. It describes the engineering and manufacturing philosophy employed, laboratory testing procedures with results presented and applications for the SSC resistant drillpipe. Since NACE MR 0175/ISO 15156 does not address friction welds the engineering team developed unique and innovative criteria together with testing procedures for the new weld technology. A new patent pending four-point bending test procedure and fixture were developed that employed unpolished samples that represent the surface finish of the product in service, in contrast to the polished samples used in NACE TM-0177 testing. This paper provides background information on the evolution of sour service drillpipe and reviews case histories where sour service drillpipe has been successfully used including the new pipe with SSC resistant friction welds. The paper can benefit drilling engineers involved in critical sour drilling operations.
Sour Service Drillpipe
The drillpipe assembly incorporates a tool joint that is typically manufactured from a forging and a friction weld that attaches the tool joint to the upset of the pipe body. This is the same manufacturing configuration that has been employed on drillpipe for decades and has been adapted to incorporate materials that resist SSC for dritical sour applications. The manufacturing technology for critical service drillpipe has evolved significantly in the last several years. Major advances relating to pipe specifically developed for use in areas with significant H2S content have been realized.
Sulfide Stress Cracking (SSC) due to the presence of H2S gas in the downhole drilling environments has led to the development of sour service drillpipe, which is engineered to have resistance to SSC. Previously available sour service drillpipe was comprised of an SSC resistant upset to grade tube and tool joint. The friction weld areas that are used to join the tool joints to the upset ends of the tubes were not manufactured for resistance to SSC.
The weld area of sour service drillpipe has not been SSC tested in the past, and there have been no documented SSC failures in the weld zone of sour service drillpipe. There are several factors that make an SSC failure in the weld zone of sour service drillpipe unlikely. The region on both sides of the weld has a much larger cross-section (1.5 to 2.0 times) than that of the tube. This larger weld area cross-section means the stress experienced in that area is less by the same proportion. This reduced stress makes the likelihood of failure due to SSC significantly less likely. It is generally possible during drilling operations to control the well environment and help prevent SSC failure of the drillpipe and weld zone.2 Implementing the following practices can help control the drilling environment and prevent SSC:
- Maintain the drilling fluid density to minimize formation fluid influx.
- Neutralize H2S in the formation fluids by maintaining a mud pH of 10 or higher.
- Utilize sulfide chemical scavengers and/or corrosion inhibitors.
- Use oil-base drilling fluids.
Deposition of mineral scales is the root cause of many production problems in oil and gas operations. These scale deposits have resulted in formation damage, production losses, significant rate and pressure reductions, and equipment failure because of corrosion issues. The most commonly encountered mineral scales in the oil field are carbonates and sulfate-based calcium sulfate, barium sulfate, and strontium sulfate scales. However, a more unusual form of these mineral scales, zinc sulfide, has recently been reported.
This paper focuses on the systematic study of a zinc sulfide scale and the operation that removed it from a well in the Gulf of Mexico. Identifying the scale form and composition and the factors affecting its dissolution resulted in a treatment that successfully removed the scale, thereby enhancing gas production from the well.
This scale was identified as wurtzite, a form of zinc sulfide scale. Extensive laboratory testing considered acid solubility and other scale-removal issues at downhole temperature and pressure conditions, as compared with the theoretical solubility of zinc sulfide in hydrochloric acid (HCl). The study also determined that other factors may affect the real-world dissolution efficiency of the acid: pressure changes, hydrogen sulfide scavenger concentration and type, the ratio of acid volume to scale weight, pre-treatment oxidizer use, and pH values that prevent reprecipitation of dissolved scale.
This paper will describe the prejob testing process and a field case history of a coiled-tubing acid scale treatment that effectively removed the zinc sulfide scale from tubulars and the formation. Data will be presented showing the composition of the acid-flowback samples as well as the treatment and production charts.