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Heikal, S.. (Eni Pakistan Ltd.) | Santellani, G.. (Eni Pakistan Ltd.) | Sultan, A.. (Eni Pakistan Ltd.) | Mugheri, S.. (Eni Pakistan Ltd.) | Eisa, H.. (Eni Pakistan Ltd.) | Iqbal, J.. (Sprint Oil & Gas Services)
ABSTRACT Formation damage removal using matrix acid stimulation in Sandstone reservoir is recognized as a risky production optimization operation, however, a good understanding of formation mineralogy, root cause of formation damage, and stimulation procedures can help reduce the risk and increase the chance of success. The scope of this paper is to share Eni Pakistan’s workflow which lead to successful matrix acid stimulation campaigns in Bhit, Badhra and Kadanwari fields. Prior to the damage removal operation, the selected wells’ deliverability analysis showed low productivity as compared to the ideal one. To restore the ideal wells’ productivity index, detailed damage analysis was performed as per following workflow. Perform pressure transient test to evaluate and quantify the level of damage Evaluate individual perforation contributions using production logging tools Assess the origin of damage by reviewing the drilling, completion operation Estimate the possible gain in production after removing the damage Define the proper chemical requirements and design the stimulation procedures and perform Post stimulation analysis to optimize the stimulation procedure prior to the next job if required. Seven candidate wells were selected for damage removal operation. The matrix stimulation operation resulted in incremental daily production of up to 160%. The increase in the production rate was accomplished by regaining the wells’ potential deliverability. This helped improve the fields’ reservoir management, accelerating hydrocarbon recovery and adding to the reserves.
Valzania, S.. (eni E&P) | Kfoury, M.. (eni E&P) | Grandis, M.. (eni E&P) | Valdisturlo, A.. (eni E&P) | Fanello, G.. (eni E&P) | Guerra, L.. (eni E&P) | Heikal, S.. (eni Pakistan) | Kashif, A.. (eni Pakistan) | Sultan, A.. (eni Pakistan)
Abstract Kadanwari field in Middle Indus Basin (Pakistan) was discovered in 1989 and brought on stream in 1995. The producing reservoirs are Cretaceous Lower Goru sands D-E-F-G. The gas production started from better quality E and F sands; after 2004 layer G started to drain western block of the field, with the first hydraulic fracture job made in Pakistan (well A). Layer G represents a complex target for petrophysical characterization; reservoir sandstones are micro-porosity rich, with variable presence of Chlorite affecting flow properties. Positive results encouraged the operator to drill & frac well B and to consider possibility to extend gas production throughout western block, including sand reservoirs of variable quality, from moderate to tight. The paper describes how reservoir study faced layer G complexity and how production data of wells A and B allowed a post frac-job evaluation integrating well-test data and frac-job interpretations into 3D dynamic model. After history match, the computed GOIP suggested an infilling program in G sand reservoir, with side-tracks of existing wells and new wells, all hydraulically fractured. So far, one sidetrack and one new well have been drilled; results fully confirmed the complexity of local geological setting. The sidetrack revealed rock quality slightly better than expected (frac not necessary). Pilot well C targeted G-Sand in a sweet seismic anomaly in western area, a gas flare was observed during DST pre-frac. Mini-Fall Off was conducted to estimate closure pressure and effective mobility, but permeability computed from MFO was not conclusive due to important filtrate invasion. DST post hydraulic fracture job confirmed commercial gas rate production higher than 1 MMscfd with a peak of 3.5 MMscfd. The successful pilot well results open new horizon to improve reserve from tight sand of Lower Goru formation.
ABSTRACT: Middle Indus Basin of Pakistan is well established gas prone area witnessed by many producing fields. Most of the discoveries are from three way dip closure with one side bounded by strike-slip fault. The faults with spatial continuity are proven to be sealing at Lower Goru E-Sand level of Cretaceous age. Consequently, the lateral continuity of the fault gains key importance in establishing trap integrity. The challenge becomes even bigger where seismic data has poor to fair S/N ratio. It is evident on 3D data that strike-slip fault when grown upward fault evolved into en-echelon pattern. At places, where the data becomes week at E Sand Reservoir which sits at an intermediate level exhibit an apparent en-echelon pattern whereby masking the continuity of main strike-slip fault. This paper is focused to find a method to establish weather the faults which appears to be en-echelon on seismic are really en-echelon or a continuous strike slip fault with adjoining normal faults. Due to minimal vertical throw of the strike-slip faults it becomes difficult to identify these faults on weak seismic reflector, while its branching faults having relatively larger throws become prominent and appears to be in en-echelon pattern, while the main strike slip fault is masked. To resolve this issue a method adopted was to look for some strong reflectors above and below the main reservoir, and then run seismic attributes to these strong reflectors instead of the main reservoir. This method worked very well in Middle Indus basin especially in Kadanwari gas field and Gambat Exploration License where the prospectivity was hampered by apparent pseudo en-echelon fault patterns. The method identified obscured faults to be a continuous strike slip fault, and was proven by drilling results
ABSTRACT: Kadanwari field located in Middle Indus Basin (Pakistan) was discovered in 1989 and brought on stream in 1995. The producing reservoirs are Cretaceous Lower Goru sands, highly heterogynous and compartmentalized by several faults; 20 equilibrium regions were defined in 10 blocks and 6 reservoirs (G, F, E, D, C, and B). Main producer is E sand classified as conventional reservoir, the rest are generally unconventional sands with low permeability and required stimulation before production. To evaluate the field potential, a full field model was completed in 2008 suggested infilling wells with various risks related to structure, fluid levels, sand quality, drive mechanism, and initial pressure. Also potential side-tracks of existing wells and short term production optimization actions were identified. In 2009 the field experience a strong production decline, so ENI Pakistan adapts the following workflow to arrest the decline and amplify the field production to maximum possible level. - Production optimization actions; such as scale removal, rental compression, water shut-off and additional perforation - Systematic drilling of new wells; starting with low risk and multi level target objects, acquire new information from newly drilled wells, and quickly update the reservoir model to firm up the optimum candidate location for new drilling. The workflow resulted in drilling and tie-in 6 new wells in 2010 and propose additional potential 4 new wells within 2011, led to remarkable production increase from 40 to over 120 MMscfd, and tripling the field proven reserves in addition to 10 years extension in Kadanwari field life
Abstract Every hydrocarbon discovery is not of commercial scale. Once a reservoir is discovered by drilling an exploration well with encouraging results with presence of hydrocarbons, an extended testing period starts to authenticate the in-place hydrocarbon volumes and deliverable rates and gain more knowledge on reservoir driving mechanism, heterogeneity, geometry, etc. which helps to make field development plan and hence the declaration of commerciality. OMV Pakistan GmbH. has two discoveries in year 2007, Tajjal and Latif. Tajjal reservoir was discovered in May 2007 in Gambat Exploration License, whereas Latif was discovered in February 2007 in Latif Exploration License. Tajjal is located in south-east of Sawan gas field and Latif is in south-east of Miano gas field, operated by OMV GmbH. Both Tajjal and Latif wells were suspended for almost a year and half until gas pipelines laid from Tajjal and Latif to Sawan CPP and Kandwari CPP respectively for processing the raw gas. Couple of wells drilled in each discovery based on G&G input before start of EWT period as a part of field appraisal plan. In January 2009, extended well test (EWT), an extended testing period started to confirm the in-place volumes and instigate the field development plan for both the discoveries. EWT is planned to acquire dynamic data for Tajjal & Latif, on average after every 3 months of production a flow after flow test & build-up data have been acquired for estimating reservoir pressure, permeability, type of aquifer & skin factors. Acquired reservoir pressure have substantially used for estimating Gas Initially In Place (GIIP). Gas in-place estimates are made using EWT data by different techniques; P/Z plots, flowing material balance, analytical model, numerical model and well test evaluations. Results from these methods are reasonably comparable. A resolution will be drawn at the end of EWT phase regarding declaration of commerciality and hence full field development.
Abstract Scale deposition, either in the formation, well bore or in the production facilities is a challenging problem in the petroleum industry. Scale problems are generally associated with the deposition of inorganic minerals, such as calcium carbonate (CaCO3) and sulfates of calcium, strontium and barium. Downhole mineral scaling is either a product of self-scaling of the formation water (FW), (carbonate scale associated with changes in pressure and/or pH) or the mixing of incompatible waters (FW and injection water) with elements of other wellbore fluids or other minerals. The cost of scale buildup can be high, both in terms of deferred production and necessary remedial treatments. Depending on the nature of the scale and the fluid composition, the deposition can take place within the reservoir, near the wellbore perforation tunnels which causes formation damage, or in production facilities subsurface and on surface with severe operational problems. The Cased Hole Gamma Ray measurement has been proven quite effective to detect the presence of scale, due to radioactive content proven by the Scale XEM/EDAC analysis. The Scale solubility analysis has proven more than 95% of the sample, are soluble in 10%-HCl based acid. Finally, the two case studies of Miano field have brought a new game changer for operations, to enhance the gas production. It is based on historical well observation, since no water production had been observed at the surface in one of the case study, so Scale was not considered to cause the production decline. Therefore the method of Cased Hole Gamma Ray measurement can be in some cases the only indication of scale build-up if other indicators are missing. Furthermore it’s also an effective method to prove scale build-up inside perforations if hole is fully accessible. This paper describes the buildup of scale, its detection and its successful removal with coiled tubing in high temperature gas wells of Miano Field. Furthermore it will show some lab results, the execution and evaluation the results of a successful operation, which resulted in a restoration of high productivity.
Lolon, Elyezer (Pinnacle Technologies) | Quirk, David James (Pinnacle Technologies) | Enzendorfer, Christian Karl (OMV UK Ltd.) | Bregar, Udo Bernhard (OMV A.G.) | Qayamuddin, Syed (OMV Pakistan Exploration G.m.b.H) | Mayerhofer, Michael J. (Pinnacle Technologies) | Cipolla, Craig L. (Pinnacle Technologies)
Abstract This paper presents the results of a fracture feasibility and design study, treatment execution and post treatment evaluation for a hydraulic fracture campaign in the Sawan and Miano Gas fields, located in the Sindh Province, Pakistan. This first successful fracture campaign (in four wells) was conducted from December 2005 to July 2006. One well is located in the Miano and three wells in the Sawan gas field targeting the Lower Goru B and Lower Goru C sands at depths of about 3,300 m. Several injection tests and minifracs prior to the main treatment were performed to quantify closure stress, fluid leakoff, perforation friction, near-wellbore tortuosity, and fracture complexity. Issues such as formation water sensitivity and fines migration are discussed. High reservoir temperature, proppant flowback issues and risk of fracing into a water transition zone are some of the challenges faced during the fracture campaign. A variety of fracture design sensitivities were performed to evaluate the effects of pad size, treatment size, fluid and proppant types on fracture geometry, conductivity and gas production. In the Sawan, fracturing was found to be simple as opposed to more complex fracturing in the Miano area. Permeability ranges from low 0.06 mD to moderate 8 mD in the four fractured wells. Treatment designs were adjusted accordingly to minimize screen-out risk and maximize fracture stimulation efficiency. To help reduce proppant flowback into the wellbore, partially cured, resin-coated proppant was pumped at the end of the treatments. A low-polymer loading, high-temperature, CMHPG fracturing fluid was used due to a high-temperature reservoir. This type of fluid provided high fluid viscosity for proppant transport while also minimizing polymer damage to the proppant pack. The fracture campaign has successfully increased the gas production by two to four folds. Introduction The Miano and Sawan gas fields are located approximately 80 kms south of Sukkur in the Sindh Province, Pakistan (Figure 1). The Miano field was discovered in 1993 and Sawan field was discovered in 1996. The produced gas is dry and condensate drop out is very little during the entire field life. The main reservoirs are the Lower Goru sands. Prior to this fracture campaign, wells had been producing from the higher permeability zones. To sustain gas supply for the plant, a number of wells in lower permeability areas were evaluated for hydraulic fracture stimulation. The primary targets for propped fracture treatments were the low to moderate permeability Lower Goru intervals. The sands are classified as sublitharenites to lithic arenites with a high content of partially altered basic volcanic rock fragments and pore-lining or pore filling iron chlorite cement.1 The main reservoir of the Lower Goru C interval is represented by bioturbated and cross-bedded delta front sandstones.2 Hydraulic Fracture Feasibility and Design A total of four wells were selected for this study (Well-A in the Miano field and Well-B, Well-C, and Well-D in the Sawan field). Table 1 shows the reservoir and fracture properties for the four fractured wells. The permeability ranges from low 0.06 mD to moderate 8 mD. The initial average pore pressure is about 4,700 psi in the Miano field and 5,300 to 5,400 psi in the Sawan field. The reservoir temperature ranges from 335 to 350ºF. The objective of the study was to evaluate the feasibility of hydraulic fracturing and provide a fracture design for the Lower Goru C and B intervals. Figure 2 shows a log correlation of wells in the study area (excluding the newly drilled Well D).
Abstract OMV Pakistan applied an original design of Genesis XT fixed cutter bit with improved features for bit stability to drill the 8.5" section of Sawan-11 development gas well in southern Pakistan. Multiple vertical wells were drilled in this field with similar parameters and operating conditions. Latest proven technology was applied successfully to drill the 1760m of 8.5" section with record ROP of 25 m/hr which is more than twice as fast compared to previous wells records. Instantaneous rates in excess of 70 m/hr were also recorded while drilling this section. This section was previously drilled with multiple bit runs using multiple roller cone and PDC bits. Later, this was reduced to 2–3 PDC bits and now the complete section has been drilled with one PDC bit (HC 606Z). Dull grading comparison with bits used in the offset wells will also be discussed. The lithology of the drilled section consists of Ranikot formation (dominating claystone with inter bedded sandstone and siltstone). Throughout this zone bit stability and optimized drilling parameters of the bit were key factors affecting its performance. Below this zone Upper Goru (UG) and Lower Goru (LG) formations are found. UG Member mainly consists of marl with streaks of limestone having an UCS of > 35 kpsi in its contact with the Ranikot formation. This type of formation is generally the most difficult to drill. LG Member comprises of claystone and siltstone with occasional traces of pyrite having UCS of 20–25 kpsi. Towards the end of section, last 400m witness increased percentage of abrasive siltstone which affects cutter's sharpness and reduces the ROP. Offset data conforms that around this point bits quit drilling. However, at Sawan-11 bit maintained its sharpness and good ROP till the end of this section. Introduction Over the past few years, the degree of difficulty and cost of drilling an oil & gas well have increased globally. With the recent oil & gas price hike, exploration and development operators have expanded their operations substantially around the globe. With the help of advanced drilling technologies like RSS, MPD, etc. and high performance drilling fluids although sometime help and prove their worth. Nevertheless, if the drilling bit is not of appropriate design, then these advanced systems and technologies can't help drilling a well efficiently and economically. OMV has been drilling gas wells in the Middle Indus basin of Pakistan since 1994. Drilling in this area is very challenging due to inter layered geological sequence that consists of clay, shale, limestone, with sand and siltstone (Figure 1). Wells are normally drilled vertically through these geological sequences which provide significant challenge to the bit performance. Previously OMV has attempted to drill these wells using roller cone, tungsten carbide inserts, and polycrystalline diamond compact (PDC) bits. But this required a lot of patience and extra rig cost due to low ROP. Many operators and bit companies have reported that PDC bit in general performs well, produces better ROP and usually drill more meters than tricone bits . Yet the cutters on the PDC drill bits normally wear out quite easily due to excessive torque. This mostly occurs when the cutters encounter any hard and abrasive formation. This process makes the PDC cutters flat, dull and unable to penetrate the rock efficiently. Nevertheless, recent PDC drill bit cutter and design technology have made it possible to drill thru some of the very hard, abrasive and interbedded formations having UCS of >30 kpsi .
Abstract Losses while drilling are a serious concern to oilfield industry. Loss of expensive drilling fluid increases the overall cost of the well. Rig time spent curing the losses can represent significant cost overruns for the well. In extreme cases well control may become an issue. The general practice to control losses starts from diagnosis of the cause. The common solutions to manage the loss circulation problem include drilling fluid treatments involving decreasing the density, controlling the viscosity and addition of lost circulation materials (LCM), controlling the drilling parameters, and placement of cement plugs. This paper will discuss the treatment of drilling fluid with Advanced Engineered Fiber (AEF), the mechanism of action of AEF and its successful application as a solution for lost circulation in Pakistan. Introduction Lost circulation is a common problem encountered during drilling. This problem can result from minor to extremely expensive and dangerous situations. The severity and persistence of a lost circulation problem are determined by the type of formation to which fluid is being lost. Generally lost circulation can occur in cavernous or vugular formations, highly permeable zones and fractured (natural or induced) formations. OMV in Pakistan had serious lost circulation problems in the Sawan field while drilling the Sui Main Limestone (SML) and Ranikot formations. Geologically Sui Main Limestone and Ranikot formations are fractured lime stones interlayered with thin beds of sand stone and clay stone respectively. Furthermore it is hard to reduce drilling fluid density below 8.9 lbm/gal due to stability problems of the Ghazij shale overlain SML Stone (fig-1) Losses in this area could range anywhere from 3,000 bbl of mud per well in the SML formation. While drilling the Sawan-3 well more than 20,000 bbl of drilling fluid were lost and the rig spent 8 days fighting the losses using all the conventional LCM available on the rig. Three cement plugs were required to control losses and completed the well after the unsuccessful LCM treatments. Table -1 shows the volume of drilling fluid lost in some off set wells in the area. Depending on the severity of the problem several techniques and products are available, the most common technique is to pump a high concentration LCM pill with fibers, flakes or granules, alone or in combination. Indeed, the pill pumped can fail and be lost to the formation if the LCM particles are smaller than 1/3 of the pore size or fracture width in the thief zone. The LCM's effectiveness is influenced by the material type, particle size distribution and optimum concentration determined by the lost circulation scenario (pore size or fracture width).To control losses into a rock matrix, the drilling fluid must contain some particles that are at least one-third as large as the flow path.
Summary In petroleum production, the problem of corrosive media attacking metallic structures is almost ubiquitous. Particularly severe environments are encountered in the production and transport of wet natural gas containing corrosive components, such as hydrogen sulphide and carbon dioxide. When exploring new gas fields, it is therefore a prerequisite to take into account the corrosivity of the respective fluids in all stages of the field development, material selection, field layout, and facilities design. In preparation of the subsequent production phase, reliable corrosion monitoring programs have to be selected, established, and implemented as necessary. Furthermore, the financial aspects always play an important role, thus posing a real challenge for the engineer forced to seek a compromise between economics and design. This paper gives a comprehensive overview of these considerations regarding four different OMV gas fields, two in Austria and two in Pakistan, which were successfully developed and brought onstream between 1967 and 2003. These fields not only vary in their geographical position, but also in their gas compositions, production start, and the location of gas dehydration units. One major aspect dealt with in each of these cases was material selection, including metallic as well as nonmetallic and composite materials. Where the initial decision was made in favor of carbon steel, different methods of corrosion protection, the application of corrosion inhibitors, corrosion monitoring, and intelligent pigging are discussed in the paper. A comparison of the various methods of resolution worked out for all four case histories, as well as the experience gained in more than three decades of production and transportation of wet, corrosive natural gas is presented. Furthermore, results of the ongoing corrosion monitoring measurements in operation in the mature gas fields are discussed under the aspect of the remaining facility lifetimes. Introduction To achieve long lifetimes of the production facilities, the production and transportation of wet, corrosive natural gas requires selection of suitable material and measures for combating corrosion. In addition to the liquid phase, which may show a low pH value and some amount of chlorides, the existence of the corrosives CO2 and H2S in the gaseous phase can pose serious corrosion problems. The presence of H2S, leads to the problem of general corrosion; additionally, it can lead to stress corrosion cracking (SCC) if the materials are not properly selected. Furthermore, some operational parameters, such as chlorides in the produced water and high temperatures, can intensify the corrosivity of the fluids. Stress corrosion cracking is taken to be one of the most dangerous forms of corrosion because it can result in an unexpected failure of a component, causing shutdown times and high financial losses caused by the need for extensive repair or reinstallation (e.g., of a pipeline), but above all, it can also cause a potential environmental and safety risk. Carbon dioxide sweet corrosion is also a well-known problem in gas production. CO2 dissolves in brine to form carbonic acid that ionizes to yield a low-pH value. The resulting acidic solution strongly enhances the corrosion in the carbon steel pipes and facilities. The presence of CO2 can lead to corrosion rates of several mm/year if no proper corrosion protection measures are applied.