This paper presents the technical development of an operator’s drilling base oil produced from their MG3 plant which was evaluated through extensive laboratory studies and field trials prior to commercialization.
The base oil is based on a majority iso-paraffin component which gives an optimum kinematic viscosity, flash point and pour point for drilling applications. In addition, the drilling fluid has minimal aromatic content to fulfil international eco-toxicity standards set by CEFAS and US EPA, 821-R-11-004 Method 1619. The base oil is compatible with various oil/synthetic mud systems and additives with its low viscosity characteristic lesser than 2.4 cSt at 40 deg C which offers excellent drilling performance for Shallow and Deepwater wells. Furthermore, the base oil exhibits high flash point of more than 90 deg C to reduce potential fire hazard while drilling HPHT and ERD wells. At the same time, its superior pour point (as low as -42 deg C) suitable for storing base oil in sub-zero conditions and to be used as deep-water drilling fluid in extremely cold countries like Russia. Its unique high-performance properties provide exceptional temperature stability and optimum rheological properties throughout the extreme temperature profile of a Deepwater or HPHT well, thus resulting in a very low ECD despite drilling with high ROP.
Field trials were carried out to verify the base oil’s performance under laboratory conditions. The base oil was tested as base fluid in SBM for both Shallow and Deepwater wells. The Shallow well was drilled vertically in water depth of 105M with a maximum mud weight of 14.6 PPG and bottom hole static temperature of 280 deg F. The Deepwater well was drilled vertically in water depth of 1008 M and subsequently side-tracked to a maximum inclination of 46 degree. Both wells were drilled successfully without any drilling fluid related issues as compared to severe losses experienced with respective offset wells.
A total of approximately 138 oil and gas wells were drilled by the operator utilizing their own base oil till 2018 after completing the technical evaluation in 2014. From the field trials and actual drilled wells, a comprehensive database analysis was developed for future improvisation and broader performance portfolio. The main technical challenge for the operator was to engineer a drilling fluid system with base fluid and chemical additives to obtain minimal ECD for reducing lost circulation risk. The base fluid properties are ideal for Shallow, HPHT, ERD and Deepwater applications whereby the ECD margin for Deepwater and ERD drilling is often narrow as compared to shallow wells. The successful project execution of base oil for drilling represents a significant milestone, elevating the company’s base oil progress at par with other global base oil producers.
It is evident that, to quantify formation damage and to study its impact on hydrocarbon production, one must have reasonable estimates of the flow efficiency or skin factor. Several methods have been proposed to evaluate these quantities for oil and gas wells. The most common methods are multirate tests, isochronal gas-well tests, and transient well tests (pressure-buildup analysis). Multirate tests can be conducted on both oil and gas wells. In these tests, several stabilized flow rates, qi, are achieved at corresponding stabilized flowing bottomhole pressures, pwf. The simplest analysis considers two different stabilized rates and pressures.
Primasari, Indah (PT Pertamina Hulu Mahakam) | Wijaya, Geraldie Lukman (PT Pertamina Hulu Mahakam) | Hadi, Aen Nuril (PT Pertamina Hulu Mahakam) | Chendrika, Lusiana (Schlumberger) | Merati, Putu Astari (Schlumberger)
Handil is a mature oil and gas field with dozens of wells drilled within 70-m distance. It has been developed since 1975 and operated by Indonesian national oil company, PT Pertamina Hulu Mahakam. Handil shallow reservoirs are located at depths between 200 and 1500 m true vertical depth (TVD). It has strong aquifer support and unconsolidated permeable sandstone reservoirs with poorly sorted grain size, requiring gravel pack completion. Since 2005, there have been 39 wells completed with gravel pack, contributing 40% of total Handil field production. Handil gravel pack wells are facing productivity impairment; several production tests indicated that 30% of the completed zones have a very low productivity index (less than 0.5 STB/D/psi) after a few years of production.
Organic clay acid (OCA) was proposed as a matrix acidizing technology to dissolve the fines in the critical near-wellbore matrix. For many years, matrix acidizing has been used to remove formation damage or improve productivity in formations containing siliceous clay. The most commonly used treatment fluid is mud acid, which is a mixture of hydrofluoric acid (HF) and hydrochloric acid (HCl). In many conventional mud acid treatments, after an initially good response to the treatment, the production falls to levels similar to those before the treatment; this is thought to be due to the precipitation from the reaction of HF with silica material on feldspar/clay, which results in more hydrated silica gel. Unlike conventional mud acid, OCA can allow a deeper live-acid penetration into the formation and limit possible reaction-product precipitates, which will enhance the effectiveness of the stimulation treatments.
Two OCA trial treatments were executed through coiled tubing. In the first job, the chemicals created an emulsion that was not compatible with fluid on the surface facilities. Demulsifier treatment on the surface successfully diluted the emulsion. Some adjustments on chemical composition have been applied on the second job, which successfully removed the emulsion. The pilot test yielded total oil production up to 900 BOPD (4,000 BLPD) instantaneous gain with ~80% improvement on productivity by reducing skin from >100 to 5. Currently, both wells are still flowing after 6 months of production. Following this success story, more than 11 OCA jobs are planned to improve the productivity of the existing zones in 2018.
A recent matrix acidizing campaign in Handil shallow wells, highlighting the damage verification, candidate selection, acid chemistry, operational constraints, production results, and future opportunities. The logistics which include the flowback of spent acids and acid neutralization in the swamp area, and the addition of demulsifier in surface facilities will also be discussed. There were no core samples available to run a formation response test to the acid prior to the matrix acidizing treatment.
Many oil and gas resources in deep-sea environments worldwide are often located in high-temperature/high-pressure (HT/HP) and low-permeability reservoirs. The reservoir-pressure coefficient usually exceeds 1.6, with formation temperature greater than 180°C. Challenges are faced for well drilling and completion in these HT/HP reservoirs. A solid-free well-completion fluid with safety density greater than 1.8 g/cm3 and excellent thermal endurance is strongly needed in the industry. Because of high cost and/or corrosion and toxicity problems, the application of available solid-free well-completion fluids such as cesium formate brines, bromine brines, and zinc brines is limited in some cases. In this paper, novel potassium-based phosphate well-completion fluids were developed. Results show that the fluid can reach the maximum density of 1.815 g/cm3 at room temperature, which makes a breakthrough on the density limit of normal potassium-based phosphate brine. The corrosion rate of N80 steel after the interaction with the target phosphate brine at a high temperature of 180°C is approximately 0.1853 mm/a, and the regained-permeability recovery of the treated sand core can reach up to 86.51%. Scanning-electron-microscope (SEM) pictures also support the corrosion-evaluation results. The phosphate brine shows favorable compatibility with the formation water. The biological toxicity-determination result reveals that it is only slightly toxic and is environmentally acceptable. In addition, phosphate brine is highly effective in inhibiting the performance of clay minerals. The cost of phosphate brine is approximately 44 to 66% less than that of conventional cesium formate, bromine brine, and zinc brine. This study suggests that the phosphate brine can serve as an alternative high-density solid-free well-completion fluid during well drilling and completion in HT/HP reservoirs.
It is no secret that drilling fluid is crucial in drilling operations. The main function of drilling fluids is to transport drill cuttings from the bottom of the hole up to the surface. Drill cuttings then will be separated on the surface before the fluid is recycled for further drilling. This is to ensure a smooth drilling operation. A drilling-fluids rheological study is a must when drilling a well.
Extensive discoveries of basement hydrocarbon reservoirs have been made in many places of fractured granite and carbonate basement in the world. Important hydrocarbon findings were achieved in fractured granitic basement in Chad and Indonesia by means of UBD and MPD technologies.
The granitic basement in Chad and Indonesia featured with hydrostatic pore pressure gradient with narrow density windows and well developed fractures. The pore pressure coefficient of the basement of Chad was predicted in between 1.02-1.06, and an underbalanced drilling (UBD) technology with a micro-foam drilling fluid was used to make an attempt on reducing drilling fluid losses; the pore pressure coefficient of the basement of Indonesia was estimated to be 1.04, and an underbalanced managed pressure drilling (UB-MPD) technology with a synthetic based drilling fluid was utilized to avoid drilling fluid losses and in favor of hydrocarbon discovery.
Different drilling technologies or modes received different results although drilling in same fractured granitic basement with similar pore pressure. Losses and kicks continued almost all the time during drilling, coring and wireline logging in some wells during UBD in Chad. Losses happened as soon as the rig pump started while overflow occurred no sooner than the rig pump stopped. However, the potential problem of losses and kicks was completely controlled by utilization of UB-MPD technology in Indonesia. No losses were found during underbalanced managed pressure drilling, tripping, connection, and circulation. Nevertheless, both basement hydrocarbon reservoirs in Chad and Indonesia have been obtained important discovery. Crude oil returned to the surface during UBD in Chad and abundant natural gas produced during UB-MPD in Indonesia.
Both UBD and UB-MPD technologies are effective to gain the discovery of fractured granitic basement reservoirs. The underbalanced MPD technology, a precisely pressure controlled drilling system, is able to accurately control the annular pressure profile throughout the wellbore, therefore it could effectively achieve safe drilling in narrow density window and cut non-productive time. It is proved to be more effective and safer in drilling of fractured granitic basement.
Banyu Urip crude contains 26% wax which can provide flow assurance (FA) challenges in a stabilized crude pipeline exposed to lower temperatures. Injection of Pour Point Depressant (PPD) chemicals has widely been considered as an effective method to ensure flow assurance for moderate waxy crude. For the Banyu Urip field in Indonesia, PPD injection was compared to other methods and found to be the best option from a cost and operability perspective. Nevertheless, it still contributes to almost 20% of Banyu Urip operating costs. Optimization of this chemical usage brings benefit both for the Operator and also for the government through lowering operating costs.
In the past, the flow assurance of waxy crude was determined by measuring \Pour Point (PP) temperature. At temperatures below this PP, the crude will stop flowing. PP measurement has several limitations, including providing a lower representation of the actual conditions. In this paper, a restart pressure simulation model and pilot experiments were used to provide a more realistic condition assessment and helped to avoid over-injection of PPD.
In the enhanced gel strength concept, a weak waxy crude gel may be formed in the pipeline below its PP and still be breakable by applying pressure within the pipeline's Maximum Allowable Working Pressure (MAWP). Furthermore, the size of pipeline and the wax's natural insulation capability provides a radial temperature profile which can prevent the core pipeline from seeing a rapid temperature reduction. A pilot experiment for establishing a radial temperature profile has been conducted in by the Operator leveraging local university support. The same approach will be conducted for an upcoming flow loop experiment for restart pressure validation.
In Banyu Urip, the initial PP target was set at 24°C based on the lowest seabed temperature observed in the offshore section of the pipeline. This target resulted in a PPD injection dosage of ~500 ppm. Using the enhanced gel strength concept, the required PPD injection rate was reduced to ~300 ppm. Further reduction is expected after conclusion of the radial temperature profile and flow loop experiments.
Kong, Deyuan (Chevron Energy Technology Company) | Hoelen, Thomas (Chevron Energy Technology Company) | Mcmillen, Sara (Chevron Energy Technology Company) | Vidra, Timothy (PT. Chevron Pacific Indonesia) | Chitra, Sarah (PT. Chevron Pacific Indonesia) | Saputra, Dicky (PT. Chevron Pacific Indonesia) | Kuswardani, Tyas (PT. Chevron Pacific Indonesia) | Kurniawan, Yohanes (PT. Chevron Pacific Indonesia) | Pandjatan, Yusak (PT. Chevron Pacific Indonesia) | Widiyanto, Adi (PT. Chevron Pacific Indonesia) | Armpriester, Cari (Chevron Environmental Management Company) | Mardalina, Melda (Ministry of the Environment)
AbstractTotal Petroleum Hydrocarbons (TPH) in soil is often measured to determine if soils have been impacted by crude oil. PT. Chevron Pacific Indonesia (CPI) operates several oil fields in Sumatra and samples soil for TPH content for remediation-related work. Traditional laboratory methods used to analyze for TPH in soil require three to four days, and commercial labs often take two to four weeks before reporting results. This timing results in delays in decision-making regarding site soil delineation and excavation as well as in determining when soil remediation has been completed. CPI conducted two pilot studies using commercially available rapid TPH test kits and one non-destructive infrared method. In the first pilot study, six different commercially available field test kits were evaluated for rapid TPH analysis plus a modified FTK (field test kit) with infrared method. Each test method was used to measure TPH from 63 soil samples. These samples covered a wide range of soil type, oil content, and moisture content, and should, therefore, be representative of most CPI sites. The TPH results were compared to the standard TPH analytical method, TPH-Gas Chromatography (TPH-GC) (USEPA 8015). In the second pilot study, a portable handheld infrared (IR) Instrument was tested with over 300 soil samples from variable CPI sites. The standard TPH-GC analytical method data of those soil samples were used to create two site-specific models with 15-20 double-blinded samples to validate the modeling work. The validated models will be loaded onto the individual instrument for future field deployment.Two of the six commercially available test methods produced TPH results similar to those obtained by the standard laboratory TPH-GC methods. The rapid, portable IR method also provided TPH results that correlated well with standard TPH-GC results at different concentration levels. The advantage of the rapid IR method is that the soil samples do not have to be extracted with a solvent, so no chemical waste is generated. The rapid IR method provides TPH results in a few minutes rather than in days or weeks. This paper describes the results from the two pilot studies, and the pros and cons of each rapid method for field application are discussed.
This paper is expected to be a lesson Learns of using nitrate-based fluid as an alternative solution to improve drilling performance and production optimization old wells.
This Lesson Learns begins from literature studied, laboratory test, field trials and continuous improvements.
Nitrate Completion Fluids have good solubility for wide range of contaminants. Furthermore, it may have some well stimulation effects. Return permeability testing of sandstone coring samples after immersion fluid completion Nitrate, in some conditions, showed some increase in the value of return oil permeability (Ko) from 25.55 to 36.25 mD.
In the field of applications, it has been tested as an additive and drilling mud on one of the deepest wells in Indonesia (5850 m) in Seram. As the additive, used in NaCl polymer mud system in order to reduce levels of solids and chloride, without changing the other mud properties significantly. With decreased levels of chloride, the corrosion rates of drilling and production equipments are also decreased. As a completion fluid, Nitrate CF have been used in the workover wells in South Sumatra and Riau. As a washer on perforation wash job, it is capable of delivering up to 20x increase in oil production and gas production compared to the previous 3x. Operationally, it has not been recorded for any Non Productive Time related this fluid.
Nitrate based fluid is an alternative completion fluid products that have been developed as an additive, mud drilling and stimulation fluids. Nitrate based fluid is sold in powder or liquid forms. Nitrates are also the basic ingredient of fertilizer. Nitrate Completion fluids have a density specification up to 1.75, the corrosion rate is lower than 10 MPY @350 deg F with standard carbon steel corrosion coupon, 5 NTU turbidity and pH 6-9, with pH buffering capacity, so it has a resistance to contamination of sour gas, having properties endotermic and environmentally friendly reaction.